N E W S L E T T E R W I N T E R 2 0 0 6

UP FRONT WITHCHRIS WRIGHTHappy New Year! The

industry has just finished

another year of feverish

development activity. Who

knows, someday explora-

tion may also return to

that level! As I write this

column the price of natural

gas has just dropped below

$10 from over $15 only a

month ago. Again we see

that high prices curtail

demand. The basic sup-

ply-and-demand principle

of economics still works!

Of course I say this tongue

in cheek because I am

continually amazed at how

frequently and prominently

folks want to deny or

ignore this most basic prin-

ciple of human behavior.

Pinnacle expanded our

operating horizons sub-

stantially in 2005. For the

thirteenth consecutive year

we increased the number

of operating companies

we call clients, with our

2005 total being just shy of

200. We also brought our

diagnostic technologies

to new horizons. In the

search for the “next Barnett

Shale” we mapped in east-

ern New Mexico, southern

Oklahoma, Kentucky,

Ohio, Alabama, and west

Texas. For the first time

we mapped—both tilt and

microseismic—on several

projects in China. Pinnacle

diagnostics made inaugural

appearances in many other

areas including Alaska’s

north slope, northern

British Columbia, and new

horizons in the Middle East.

2005 also saw the introduc-

tion of FracproXACT, the

industry’s first design-only,

reservoir-specific, calibrated

fracture simulation model.

This newsletter has two

feature articles: a fracture

mapping case study of

Williams Energy’s efforts to

optimize completion, frac-

turing, and well placement

strategies in the Piceance

basin; and a technical over-

view by Norm Warpinski of

how subsurface fluid flow/

reservoir deformation are

tracked with continuous

surface tiltmeter monitor-

ing. This work was led by

Dr. Jing Du, a longtime

Pinnacle veteran and one

of the first to literally get

a PhD in tilt data analy-

sis—and a Longhorn to

boot! After reading Norm’s

brief and lucid overview, I

realized that Norm and not

I should have presented

this work at this year’s SEG

in Houston. Then again, if

I could change the past I

would have remembered

to bring the wedding ring

up to the altar!

Our downhole-tool devel-

opment efforts got a large

boost at year-end with

the addition of Ken Smith,

a 25-year downhole tool

design veteran, to lead our

Sustaining Engineering

Group in Houston. The

back page also lists the

many other additions to

team Pinnacle since our last

newsletter. I wish everyone

a happy and healthful 2006.

See you soon…

Chris Wright

President of

Pinnacle Technologies

THE BACKGROUNDWilliams Production Company performed a study to im-prove hydraulic fracturing and fi eld development in the Williams Fork Formation, Piceance Basin, Colorado (Fig-ure 1). Hydraulic fracture mapping was performed with microseismic imaging on wells in the Grand Valley and Rulison Fields.

The Williams Fork Formation is part of the Mesaverde Group and consists of many stacked low permeability sandstones. Formation gross thickness can exceed 2000 ft. A generalized Mesaverde section is shown in Figure 2. These are low permeability sandstones with porosities ranging from 6–14% and matrix permeability ranging from 0.0001–0.005 millidarcies. All intervals are naturally fractured and the fractures generally terminate at litho-logic boundaries so they do not connect many layers ver-tically. Layers are very limited in lateral extent and there is little or no correlation of intervals even with reduced well spacing.

Gas in place averages 100–140 billion cubic feet (bcf ) per 640-acre section. Estimated ultimate recovery (EUR) per well is 1.3–1.7 bcf in core areas. The recovery factor for wells on 20 acre spacing is approximately 40% and for 40 acre spacing it is approximately 20%. At the time of this pilot, Williams’ fi elds were primarily developed on 20–40 acre well spacing. The fracture mapping was part of a larger pilot project to evaluate 10 acre well spacing for some areas as well as to compare geometries obtained with conventional gel fracs versus waterfracs.

Beginning in 2001 some wells were stimulated with waterfracs. Typical waterfrac designs consisted of 80,000-140,000 gallons of slickwater and 90,000–160,000 pounds of 20/40 sand pumped at 40–50 barrels per minute (bpm). Typical gel frac designs consisted of 60,000–140,000 gal-lons of 30# crosslinked gel and 300,000–700,000 pounds of sand pumped at 40 bpm. Frac stages covered gross intervals of 300–500 feet with four to six sets of perfora-tions. Both the waterfracs and gel fracs were limited entry designs with 18–20 total perforations for approximately

Figure 1: Map showing location

of Piceance Basin and Grand

Valley/Rulison Fields.

CASE STUDY:GRAND VALLEY ROCKS AND RULISON ROLLS

UTAH COLOR ADO

UU N I T E D S T A T E S

Grand ValleyField Rulison

FieldParachute

Field

P I C E A N C E B A S I N

there was a general relationship between frac-

ture treatment coverage and fracture injection

pressure from the Diagnostic Fracture Injection

Tests (DFITs) which we performed. More often

than not, the intervals that had a higher injection

pressure were treated late or not treated at all.

Fracture azimuth averaged N75°W in Rulison and

N81°E in Grand Valley. The azimuth range was

much broader and varied with depth in Rulison,

possibly due to differences in structure and

stresses. Fracture half-length for gel fracs was

similar for both fields and longer than expected.

The half-length of waterfracs in Grand Valley was

more than double that mapped in Rulison. Wider

event maps and shorter fractures were seen in

Rulison, which could indicate more leakoff into

natural fractures.

THE RESULTS

Payzone coverage was good (75% to 98%) us-

ing limited entry techniques in these thick gross

intervals. Low stress/pressure zones did not dic-

tate fracture growth, which was a concern head-

ing into the project. However, there is room for

improvement. For example, the RU-2 had 75%

payzone coverage with an estimated 61 feet

of net pay not stimulated. Using a 1.6 bcf EUR

for a typical well indicates that approximately

0.40 bcf of gas might be poorly connected to

the well. Based on the microseismic mapping

results, Williams has moved to smaller gross frac

intervals to optimize payzone coverage.

Well performance results from several years of

production indicate that waterfracs are per-

forming similar to gel fracs. Williams is testing

individual sands to evaluate effective fracture

length versus mapped fracture length and to

further quantify the recompletion potential of

missed pay.

Pinnacle identified refrac potential in some wells to recover bypassed gas and recommend-ed modifications to completion and fracture de-signs. 10-acre spacing has been approved and infill well placement now takes into account fracture orientation and length for downspac-ing areas.

By now, we are all familiar with the use of sur-face tiltmeters for fracture monitoring. It is a great method for determining the azimuth and dip of the fracture. Under some circumstances, it can also be used to extract other information that can be of use, such as the depth to the cen-ter of the fracture and the fracture volume. Only in the shallowest of reservoirs is it ever possible to determine the specific dimensions—height or length.

Surface tiltmeters also can be applied to reser-voir monitoring of injection and/or production processes, such as steam flooding or water flood-ing, or for other injection processes that require monitoring (CO2 sequestration and waste injec-tion). In such applications, we employ surface tiltmeters in a bi-modal approach.

In one mode, we look for discrete events that indicate sudden changes in a reservoir. Such changes might be due to the initiation or the closing of a fracture, the slippage along a fault, or other fracture-related processes. Analysis of this mode is very similar to standard surface tiltmeter fracture monitoring and provides information on the created fractures.

It is the second mode that I would like to discuss today. We also use surface tiltmeters to extract information on the volumetric changes within

2.0 bpm/perf. Average sand concentration was 1.2 ppg for the waterfracs and 5.0 ppg for the gel fracs.

Rulison and Grand Valley have similar permeabil-ity, mineralogy and gross/net sand ratios. Depth, temperature, pore pressure, stress, faulting and structural complexity varies between fields. Mov-ing eastward from Grand Valley to Rulison, the structure deepens and there is an increase in the gas-saturated interval that will be completed along with higher fracture gradients, closure stresses, pore pressures and temperatures.

PINNACLE PERFORMS Mapping results are shown in Figures 3 and 4 for one of the wells in the Grand Valley area. For more details on this project, please refer to SPE 95637. Pinnacle’s twelve-level, three-compo-nent geophone array was utilized for this map-ping project. The G.V. wells were treated with four stages targeting the Cameo, MV1, MV2 and MV3 intervals.

Fracture azimuth varied from N77°E to N81°E. Fracture length varied from 940 feet to 1200 feet on the east wing and from 270 feet to 600 feet on the west wing. The mapping setup was clearly biased toward the east wing thus the fracture wing lengths may be symmetrical. Fracture height growth was fairly well contained within each target interval but some fractures appear to migrate from sand to sand. They start in one sand at the frac well, but as they get farther from the well, they jump up or down into a different sand, likely due to sand body or permeability pinch-outs.

More detail on fracture initiation and payzone

coverage can be found in the SPE paper. It is

apparent that fracture initiation is not always

in the lowest stress or lowest pressure zone but

Figure 2: cross section showing the targeted interval.

Figure 3: Plan View for GV-1 fracs, the observation well is biased toward the eastern wing of the fracture.

NORM’S NOTES:SURFACE TILTS: LOOKING INTO THE RESERVOIR

Figure 4: Side View fracture map of GV-1 well where zone coverage and fracture height growth can be seen. Notice how some fracs appear to “jump” over into adjacent sands away from the wellbore.

MESAVERDE GROUP Thickness Range (3500'–4600')Depth Range (3200'–3700')

Cameo 850'

Rollins 350'

Cozzette 300'

Concoran 120'Illes

Fo

rmat

ion

Will

iam

s Fo

rk F

orm

atio

n (2

800'

–380

0')

Gas Bearing Sequence(1700'–2400')

1000

800

600

400

200

0

-200

-400

-600

-800

-10000

West-East (ft)

-1200 -800 -400

Sou

th-N

ort

h (f

t)

400-1600

4400

4600

4800

5000

5200

5400

5600

5800

Dep

th (f

t)

800

Distance Along Fracture (ft)

-400 0 400 1200-800

MV1

MV2

MV3

GV-1 Frac Well

GV-3 Observation Well

GV-1 Gamma Ray

GV-3 Gamma Ray

N E W S L E T T E R W I N T E R 2 0 0 6

the reservoir that occur over long time periods, and our processing algorithm for doing this has been dubbed the “Volume Calculator”. The Vol-ume Calculator is basically an inversion of the ef-fect of volumetric change within the reservoir on the surface tilts. The actual equations used are for-mulated for poro-thermo-elasticity, implying that we are considering the effects of pore pressure and temperature changes on the elastic deformation of the reservoir, but we can also simply invert for volu-metric changes if we know nothing about reservoir properties, temperature changes, pore pressure distribution, or other needed information.

Let’s start with a little background. The whole idea of extracting reservoir information from surface deformation appears to have started with Geertsma in the 1960’s, as far as I can tell. Geertsma, who was a pioneer in rock mechanics, poro-elasticity, fracturing, and many other fields, was interested in the surface subsidence induced by the depletion of a reservoir at depth. He showed how one could use an approach called “nucleus of strain” to get relatively simple solu-tions for these very complex problems and, in particular, gave results for a disk shaped reservoir. Of course, surface subsidence is just a larger-scale manifestation of the surface deformation that we measure with tiltmeters.

Using Geertsma’s approach, we can easily show the surface deformation and the tilt (the gradi-ent of the surface deformation) induced by the draining of a reservoir or other processes, as

shown in Figure 5 below. Included on the figure are the deformation and tilt for a disc-shaped and a rectangular reservoir, with the two differ-ent directions indicated for the rectangular res-ervoir. Even small changes in volume can create large-scale changes in the tilt field that can easily be measured. We can use simple models like these to back out the changes in the reservoir that induced the measured tilt field, but we need some constraints or the problem will not have a unique solution. The easiest and most practical constraint to apply is to confine the volumetric changes to the reservoir. Now we can deduce what size zone and what volumetric change in-duced the surface tilt pattern.

Unfortunately, simple models like these will not get us very far when there are multiple injection and production wells in a reservoir, permeability anisotropy, reservoir variations, and all sorts of other factors that complicate such an analysis. This is where the Volume Calculator comes into play. One of our reservoir experts—Dr. Jing Du —has developed a much more sophisticated approach to this analysis that allows for reser-voir wide variations in the deformation. The analysis is based on work done by Segall, who extended Geertsma’s approach and developed solutions using Green’s functions that provide considerably more flexibility. Jing uses these types of Green’s functions in the Volume Calcula-tor to extract more complicated reservoir defor-mation patterns.

The way this works is as follows. The region of deformation is constrained to the reservoir in-terval, as before, but now the reservoir is divided into some number of rectangular blocks that contain the entire area where deformation is oc-curring. The number of blocks, and therefore the size of the blocks as well, are dependent upon

the number of tiltmeters that have been used. With more tiltmeters, we can use finer and finer block sizes to extract more detailed information. The Volume Calculator performs an inversion that determines the best-fit volumetric change for each of the reservoir blocks to match the sur-face tiltmeter data as accurately as possible. The only other constraint is one of local smoothness which requires that adjacent reservoir blocks cannot have wildly varying volumetric changes. Now, given a set of surface tiltmeter measure-ments taken over weeks or months, we can cal-culate what reservoir changes likely caused the observed surface deformation.

Figure 6 shows an example of one such Volume Calculator result, taken from SPE 96897, which shows steam-induced deformation in one pad development in Shell Canada’s Peace River Field. This plot shows the volumetric strain in the reservoir required to induce the measured tilt field over the month of March. In this case most of the steam volume is going into the western laterals and much less into the eastern laterals. These results highlight the anisotropic reservoir flow geometry that may exist in any geologic sequence, but would not be readily discernable without such monitoring technology.

The Volume Calculator is another example of the new solutions that we are developing to pro-vide better answers about downhole processes. Along with INSAR and GPS technologies, surface tiltmeters provide an excellent solution for moni-toring of reservoir deformation.

References

Geertsma, J., “Land Subsidence Above Compacting Oil and

Gas Reservoirs,” JPT, pp. 734-744, June 1973.

Segall, P., “Induced Stresses Due to Fluid Extraction from Axi-

symmetric Reservoirs,” Pure and Applied Geophysics, 139, No.

3/4, pp. 535-560, 1992.

Figure 6:

Example cal-

culation from

steam injection

at Peace River

(SPE 96897).

Figure 5: Theoretical uplift and tilt for disc-shaped and rectangular reservoirs (equal volume) at a depth of 3,000 ft having 0.005% volumetric increase in a 30-ft zone.

.009

.007

.005

.003

.0010

Distance (ft)

1000 2000 3000

Up

lift

(ft)

4000 5000

R 798

X 2500 x 800

Y 2500 x 800

0

-.5

-1

-1.5

-2

-2.5

Tilt

(mic

rora

dia

ns)

0 1000 2000 3000 4000 5000

Distance (ft)

R 798

X 2500 x 800

Y 2500 x 800

1600

1400

1200

1000

800

600

400

200

0

No

rth

ing

(m)

800

Easting (m)

200 400 600 10000 1200 1400 1600 1800

.05

.04

.03

.02

.01

0

-.01

-.02

-.03

-.04

-.05

Volu

met

ric

Stra

in D

istr

ibu

tio

n

Tiltmeter siteWell trajectoriesContour level (.01)Minimum valueMaximum value

6.1e-0023.5e-006

Park North Technology Center

219 Airtex Boulevard

Houston, TX 77090

281-876-2323

fracHouston@pinntech.com

Return Service Requested

2006 HYDRAULIC FRACTURING SCHOOL SCHEDULE

Houston – January 18 to 20

Denver – April 12 to 14

Oklahoma City – October 18 to 20

Please contact Margaret Flores at 281-876-2323 ext.402 or margaret.fl ores@pinntech.com

January: Marcus Simmons, Project Manager, Fort WorthAndrew Alcantar, Operator, HoustonQinggang Ma, Software Engineer, Houston

December: Lindsey Hughey, Diagnostic Specialist, HoustonKen Smith, Sustaining Engineering Manager, Houston

November: Christina McMichael, Accounts Payable, San Francisco

October: James White, Project Manager, Fort WorthAndrew King, Operator, HoustonMike Simms, Operator, Houston

NEW MEMBERS OF THE TEAM

N E W S L E T T E R W I N T E R 2 0 0 6

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