Downhole Separation

Technology Performance:
Relationship to Geologic
Conditions

Prepared for
U.S. Department of Energy
National Energy Technology Laboratory
under Contract W-31-109-Eng-38

Prepared by
John A. Veil and John J. Quinn
Argonne National Laboratory

November 2004
Argonne National Laboratory, a U.S. Department of Energy Office of Science laboratory,
is operated by The University of Chicago under contract W-31-109-Eng-38.

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Downhole Separation Technology Performance Page 1

Executive Summary

Produced water is underground formation water that is brought to the surface along with oil or
gas. It is by far the largest (in volume) by-product or waste stream associated with oil and gas
production. Management of produced water presents challenges and costs to operators. If the
entire process of lifting, treating, and reinjecting can be avoided, costs and environmental
impacts are likely to be reduced. With this idea in mind, during the 1990s, oil and gas industry
engineers developed various technologies that separate oil or gas from water inside the well. The
oil- or gas-rich stream is produced to the surface, while the water-rich stream is injected to an
underground formation without ever being lifted to the surface. These devices are known as
downhole oil/water separators (DOWS) and downhole gas/water separators (DGWS).

Two basic types of DOWS have been developed. One type uses hydrocyclones to mechanically
separate oil and water, and the other relies on gravity separation that takes place in the well bore.
A more detailed description of the technologies, with figures and references, can be found in
Veil et al. (1999) and Veil (2001, 2003).

DGWS technologies can be classified into four main categories: bypass tools, modified plunger
rod pumps, electric submersible pumps, and progressive cavity pumps. There are tradeoffs
among the various types, depending on the depth involved and the specific application. Produced
water rates and well depth control which type of DGWS tool is appropriate. A good reference on
DGWS technology is a 1999 report prepared by Radian International for the Gas Research
Institute (GRI 1999).

DOWS and DGWS technologies received a great deal of attention in the late 1990s. Over the
past few years, few installations of either technology have been made. The U.S. Department of
Energy asked Argonne National Laboratory to compile a database of as many DOWS and
DGWS trials as possible and determine what set of production formation geology and injection
formation geology offered the greatest chance for a successful installation. Although the field of
geology encompasses many aspects and properties of underground formations, we focused this
study on the basic types of rocks (i.e., carbonate, sandstone, or other). The primary reason for
this was that the data we used in this analysis had only limited information on other geologic
properties.

This report provides data on 59 DOWS trials and 62 DGWS trials from around the world (Tables
1-3) and a qualitative discussion of at least 35 other installations. The data are taken from the
literature, vendor Web sites, and material directly provided by operators or vendors. We are
aware that there have been other field installations, but data on those installations are either being
held privately as proprietary information or are not available for other reasons. Despite not
including all worldwide field trials, the data compiled here represent the largest and most
complete set of information on downhole separation that is publicly available. We further note
that in some columns in the data tables, data are lacking for many trials. Although this lack of
data is unfortunate, the large amount of data compiled and reported here is still useful.

The analysis of preferable geologic conditions began by reviewing the conclusions presented at a
2002 meeting of the International Downhole Processing Group, at which downhole separation
Downhole Separation Technology Performance Page 2

experts from around the world presented their latest information. Alhanati et al. (2002) presented
an analysis of the effect of geologic conditions on the risk of a DOWS trial. Those authors
reviewed records on about 80 installations of hydrocyclone-type DOWS that used electric
submersible pumps (ESPs) for pumping. They concluded that installations having both carbonate
production and injection formations have the lowest risk of failure, or, conversely, the highest
probability of success. Installations having the following production zone/injection zone
combinations posed a medium risk: carbonate/consolidated sandstone, consolidated
sandstone/carbonate, and consolidated sandstone/consolidated sandstone. Installations with
carbonate/unconsolidated sandstone or consolidated sandstone/unconsolidated sandstone
conditions posed a medium risk for regular DOWS installations, but a high risk when the
injection zone was above the production zone. Finally, any installation that had unconsolidated
sandstone as the production zone offered a high risk.

We were unable to examine the data used by Alhanati et al. (2002); therefore, our results are
based on an independent effort. Table 5 includes qualitative performance ratings, where possible,
for each DOWS installation listed in Table 1 on overall performance, increase in oil production,
reduction in water to the surface, and longevity. This ranking scheme has shortcomings, but we
were unable to provide a more precise ranking scheme because there were gaps in the available
data. Table 2 summarizes DGWS data from GRI (1999). We do not have much information on
the trials themselves. GRI included its own performance ranking of success, failure, or economic
failure. Table 3 contains information on a few additional DGWS installations not included in
GRI (1999). Because the data records are not complete, only an overall performance rating is
shown.

Table 6 compares qualitative performance with geologic types for the 59 DOWS installations
from Table 1. Overall, about 59% of the trials were rated as good. All three categories in which
both the production and injection formations were known showed about the same percentage of
good trials (50–58%). Overall, about 31% of the trials were rated as poor. For the three
categories in which both the production and injection formations were known, the percentage of
poor trials ranged from 28% for sandstone/sandstone to 50% for carbonate/sandstone.

Table 7 compares GRI’s qualitative performance with geologic types for 48 DGWS installations.
Overall, about 54% of the trials were rated as successes. The carbonate/carbonate,
carbonate/sandstone, and sandstone/sandstone categories all showed a high percentage of trials
rated as successes (70–100%), but none of the three stood out as a clearly better combination
than the others. Overall, about 42% of the trials were rated as failures or economic failures.
Nearly half of the trials were in situations in which one or both of the formations were unknown.
This subset of trials had the worst overall success rate, with only 30% being rated as successes
and 61% being rated as failures or economic failures.

The results from Table 3 are much more straightforward. Twelve of the 14 trials were
qualitatively rated good. Five trials had sandstone/sandstone formations, and two others had
coal/unknown formations. No information on formations was available for the other seven trials.

Our analysis of about 120 DOWS and DGWS installations from numerous different countries,
states, and provinces does not support the theory that the combination of carbonate production
Downhole Separation Technology Performance Page 3

and injection formation offers the best chance for a successful DOWS or DGWS installation. On
the basis of the data described in this report, it is not possible to predict the performance or
likelihood of DOWS or DGWS success solely on the basis of the geology of the production
formation or the injection formation. One caveat to this conclusion is that the data sets reviewed
by Alhanati and his coauthors were probably much more complete than the data sets presented in
this report. We believe that our conclusions are still valid, but we recognize that we did not have
the ability to consider many details about the formation properties other than their geology into
our ranking scheme. Despite intensive efforts to obtain more complete data sets, we were
unsuccessful in that regard.

There are other factors that play a role in the success of DOWS systems. Probably the most
important factor is ensuring that the injection formation has good injectivity and that the
injection process does not introduce materials that could clog the pores of the injection formation
and reduce its injectivity. Another important parameter is good vertical and mechanical
separation between the production and injection formations. The candidate well should be
located in a formation that has sufficient remaining reserves to allow payback of the investment.

Representatives from companies that have used or have sold DGWS were contacted and asked
their opinion on the value of the geologic setting and other factors. A theme that emerged from
these discussions was that the DGWS success rate is not dependent on the geology of the source
zone or disposal zone, but rather on site-specific properties of the disposal zone at individual
wells. In general, disposal zones that are favorable for DGWS have high permeability, high
porosity, and are underpressured.
Downhole Separation Technology Performance Page 4

Chapter 1 — Introduction

Background

Produced water is underground formation water that is brought to the surface along with oil or
gas. It is by far the largest (in volume) by-product or waste stream associated with oil and gas
production. According to the American Petroleum Institute (API), about 18 billion barrels (bbl)
of produced water were generated by U.S. onshore operations in 1995 (API 2000). Additional
large volumes of produced water are generated at U.S. offshore wells and at thousands of wells
in other countries. Khatib and Verbeek (2003) estimate that in 1999 there was an average of
210 million bbl of water produced each day worldwide. This volume represented about
77 billion bbl of produced water for the entire year. Given that worldwide oil production from
conventional sources is nearly 80 million barrels per day (bbl/d, or bpd), one may conclude that
3 bbl of water are produced for each 1 bbl of oil worldwide, and that for the United States, one of
the most mature petroleum provinces in the world, the ratio is closer to 6 or 7 bbl of water per
1 bbl of oil.

In early 2004, Argonne National Laboratory (Argonne) generated estimates of onshore produced
water volumes in the United States for the year 2002 (Veil et al. 2004). Making these estimates
was challenging, since many of the states did not have readily available information on volumes.
The 2002 total onshore volume estimate of 14 billion bbl was derived directly from the
applicable state oil and gas agencies or their Web sites when data were available and
extrapolated when data were not available. The estimate does not include produced water from
coal-bed methane (CBM) wells or from offshore U.S. production. The actual U.S. total volume
of produced water in 2002 was probably much higher than the estimated 14 billion bbl.

Management of produced water presents challenges and costs to operators. The cost of managing
produced water after it is already lifted to the surface and separated from the oil or gas product
can range from less than $0.01 to more than several dollars per barrel. If the entire process of
lifting, treating, and reinjecting can be avoided, costs are likely to be reduced. With this idea in
mind, during the 1990s, oil and gas industry engineers developed various technologies to
separate oil or gas from water inside the well. The oil- or gas-rich stream is produced to the
surface, while the water-rich stream is injected to an underground formation without ever being
lifted to the surface. These devices are known as downhole oil/water separators (DOWS) and
downhole gas/water separators (DGWS). These technologies are described in Chapter 2.

Scope of Study

Argonne previously studied and described DOWS technology for the U.S. Department of Energy
(DOE) through a technology feasibility evaluation (Veil et al. 1999) and prepared several
updates on the status of the technology after that (Veil 2001, 2003). These studies pointed out the
potential for cost savings resulting from DOWS and DGWS installations. In early 2003, Argonne
was contacted by an environmental program manager from DOE’s National Energy Technology
Laboratory and asked to undertake a study of the geologic conditions under which DOWS and
DGWS were most successful. The DOE manager’s intention was to have Argonne identify oil
Downhole Separation Technology Performance Page 5

and gas formations throughout the United States that had the optimal geologic conditions to
increase the prospects of successful DOWS and DGWS installations.

This report describes the data that Argonne compiled on DOWS and DGWS installations. The
data do not support any clear trend relating specific geologic conditions to DOWS or DGWS
success. Therefore, the intended extrapolation to other U.S. formations was not conducted.

Acknowledgements

This work was supported by DOE-NETL under contract W-31-109-Eng-38. John Ford was the
DOE project officer for this work. We acknowledge the information provided by equipment
companies and oil and gas operators. The authors thank Maurice Dusseault, Jon Rudolph,
Andrew Wojtanowicz, Ted Frankiewicz, John Boysen, and Bruce Langhus for their review of
and comments on the draft report.
Downhole Separation Technology Performance Page 6

Chapter 2 — Downhole Separation Technology

This chapter describes the various types of tools that are used to separate oil or gas from water
inside of wells. The tools are generally designed either for oil/water separation or for gas/water
separation and therefore are described separately in the following sections.

DOWS Technology

DOWS technology reduces the quantity of produced water that is handled at the surface by
separating it from the oil downhole and simultaneously injecting it underground. A DOWS
system includes many components, but the two primary ones are an oil/water separation system
and at least one pump to lift oil to the surface and inject the water. Two basic types of DOWS
systems have been developed. One type uses hydrocyclones to mechanically separate oil and
water, and the other relies on gravity separation that takes place in the well bore. A more detailed
description of the technologies, with figures and references, can be found in Veil et al. (1999)
and Veil (2001, 2003).

Hydrocyclones use centrifugal force to separate fluids of different specific gravity; they operate
without any moving parts. A mixture of oil and water enters the hydrocyclone at a high velocity
from the side of a conical chamber. The subsequent swirling action causes the heavier water to
move to the outside of the chamber and exit through one end, while the lighter oil remains in the
interior of the chamber and exits through a second opening. The water fraction, containing a low
concentration of oil (typically less than 500 mg/L), can then be injected, and the oil fraction
along with some water is pumped to the surface. Hydrocyclone-type DOWS have been designed
with electric submersible pumps (ESPs), progressing cavity pumps, gas lift pumps, and rod
pumps.

Gravity separator-type DOWS are designed to allow the oil droplets that enter a well bore
through perforations to rise and form a discrete oil layer in the well. Most gravity separator tools
are vertically oriented and have two intakes, one in the oil layer and the other in the water layer.
This type of DOWS uses rod pumps. As the sucker rods move up and down, the oil is lifted to
the surface and the water is injected. Three North Sea-based companies collaborated to develop
another class of gravity-separation DOWS that works by allowing gravity separation to occur in
the horizontal section of an extended reach well. The downhole conditions allow for rapid
separation of oil and water. Oil is lifted to the surface, while water is injected by a hydraulic
submersible pump (Almdahl et al. 2000).

DOE has actively promoted DOWS technology. With DOE funding, Argonne conducted an
independent evaluation of the technical feasibility, economic viability, and regulatory
applicability of DOWS technology in 1999 (Veil et al. 1999). That report provides information
on the geology and performance of 37 DOWS installations, representing most of the installations
that had been made worldwide through 1998. Some of the key findings from those installations
are summarized below:

• More than half of the installations were hydrocyclone-type DOWS (21 compared with 16
gravity-separator-type DOWS).
Downhole Separation Technology Performance Page 7

• Twenty-seven installations were in Canada, and 10 were in the United States.

• Of the 37 DOWS trials described, 27 were in four producing areas: southeast

Saskatchewan, east-central Alberta, the central Alberta reef trends, and East Texas.

• Seventeen installations were in 5.5-in. casing, 14 were in 7-in. casing, one was in
8.625-in. casing, and five were unspecified.

• Twenty of the DOWS installations were in wells located in carbonate formations, and 16
were in wells located in sandstone formations. One trial did not specify the lithology.

• The rate of oil production increased in 19 of the trials, decreased in 12, stayed the same in
two, and was unspecified in four. The top three performing hydrocyclone-type wells
showed oil production increases ranging from 457% to 1,162%, while one well lost all oil
production. The top performing well improved from 13 to 164 bbl/d. The top three
gravity separator-type wells showed oil production increases ranging from 106% to
233%, while one well lost all oil production. The top-performing well in this group
improved from 3 to 10 bbl/d.

• All 29 trials for which both pre-installation and post-installation water production data
were provided showed a decrease in water brought to the surface. The decrease ranged
from 14% to 97%, with 22 of 29 trials exceeding a 75% reduction.

Argonne later ran a program for two years under which DOE funds were offered to companies to
subsidize the cost of installing DOWS systems in exchange for receiving detailed operating data.
Only two companies participated in this program. The data from a gravity-separator-type DOWS
trial in New Mexico (Veil 2000) and a hydrocyclone-type DOWS trial in Texas (Argonne and
ALL-LLC 2001) are available on Argonne’s Web site at http://www.ead.anl.gov/project/
dsp_topicdetail.cfm?topicid=18.

Several organizations have worked to develop a DOWS unit that separates fluids by using a
centrifuge. DOE funded development of a centrifugal DOWS by Oak Ridge National Laboratory
(Walker and Cummins 1999), but this technology has not been tested in a full-scale field
application. In May 2003, Chachula (2003) reported on a separate research effort that was
expected to complete a prototype centrifugal DOWS by the fourth quarter of 2003. As of August
2004, no publicly available papers have been identified describing a centrifugal DOWS field
trial.

One of the applications for which DOWS could be used is to improve the water handling and
production rate on a fieldwide basis. To date, DOWS have not been used for this purpose. The
following examples lead in that direction.

In 1999, DOE awarded a large grant to Venoco, Inc., a Southern California offshore producer, to
conduct a pilot application using downhole water separation units attached to electric
submersible pumps. The goal was to improve field economics and minimize water disposal in
Downhole Separation Technology Performance Page 8

the South Ellwood Field, offshore from Santa Barbara, California. Venoco had hoped to install a
DOWS on one of its wells during the first quarter of 2004, but as of summer 2004, the earliest
likely installation date is projected to be the second quarter of 2005 (Horner 2004).

Chachula (2003) discusses use of a DOWS as part of a “smart well” system that would control
real-time choking, plugging, isolation, and monitoring. He acknowledges that this is an
expensive, complex, and unproven technology.

Recent DOWS Activity

DOWS developments and new installations have been mostly stagnant for the past few years.
The lack of DOWS sales has translated into changes to the DOWS marketplace. At the time Veil
et al. (1999) was released, three companies were actively marketing DOWS tools in the United
States: Centrilift (a division of Baker Hughes), REDA Pumps, and Dresser/Axelson. During
2002, only Centrilift continued to actively market the technology, and by 2004, none of these
companies were promoting DOWS.

Because of low DOWS sales, Centrilift currently does not actively market its DOWS tools (Voss
2004a). REDA was subsequently taken over by Schlumberger, which reports that REDA’s
DOWS tool (the Aqwanot) is no longer being sold because it was not sufficiently reliable.
Schlumberger continues proprietary development of downhole separation tools and has looked at
separation devices other than hydrocyclones. It anticipates having a field prototype late in 2005
and commercialization in 2006 (Fielder 2004).

During 2000, the author was not able to contact a Dresser/Axelson representative to learn if the
company planned to continue marketing DOWS. No recent contact has been made, although
none of the persons interviewed by the author while researching this paper mentioned any
DOWS activity by Dresser/Axelson.

Texaco was a leader in developing the gravity-separator-type DOWS technology sold by

Dresser/Axelson. However, since 1999, Texaco’s core group of DOWS researchers has been
disbanding (some have retired, and others have been reassigned to different projects). One
Texaco well with an installed DOWS system was sold, and the DOWS was removed from the
well.

In Canada, Quinn Pumps marketed several DOWS tools in the late 1990s but has not had many
installations during recent years. Quinn is still marketing downhole separation systems but has
focused more on gas wells rather than oil wells (Prostebby 2003).

One new entry into the DOWS marketplace is READ Well Services, which, in conjunction with
Wood Group ESP, developed a two-stage hydrocyclone-type DOWS system and installed it in a
well operated by PDVSA in Venezuela in December 2001. The unit is sized to handle
10,000 bbl/d but was operated at 8,000 bbl/d until May 2002, when the ESP component of the
unit failed. The water separated in the hydrocyclone could be either injected or sent to the
surface via the well annulus. PDVSA and READ tested the system at various water splits (the
percentage of water separated in the hydrocyclone). The unit was set to operate at a 60% split,
Downhole Separation Technology Performance Page 9

but the tests ranged from 30% to 70% split. In the 50–70% split range, the water fraction
contained from 35 to 200 mg/L of oil (Smestad 2003). The DOWS operated for 5 months until
various components of the pump and controls (but not the separator) had failed. The DOWS was
pulled from the well and has sat on the surface for several years, where it is becoming corroded.
Because of the political upheaval in Venezuela during the past few years, no additional work has
been done at that location (Smestad 2004).

C-FER Technologies is a DOWS developer rather than a vendor. C-FER played an active role in
developing the original hydrocyclone-type DOWS systems and continues to develop new DOWS
technologies, such as the gas-lift DOWS.

Another company that already sells an industrial oil/water separation device, Gnesys, Inc., is
developing a new DOWS tool and hopes to try a pilot test later this year (Janckhe 2004).

DGWS Technology

Several companies have marketed downhole separators for gas wells. Since the difference in
specific gravity between natural gas and water is large, separation occurs naturally in the well.
The purpose of the DGWS is not so much one of separation of the fluid streams but of disposing
the water downhole while allowing gas production. The technology is somewhat different than
DOWS technology, for which the fluid separation component is very important.

A good reference on DGWS technology is a 1999 report prepared by Radian International for the
Gas Research Institute (GRI 1999). Much of the information in this section is based on that
report. DGWS technologies can be classified into four main categories: bypass tools, modified
plunger rod pumps, ESPs, and progressive cavity pumps. There are tradeoffs among the various
types, depending on the depth involved and the specific application. Produced water rates and
well depth control which type of DGWS tool is appropriate.

Bypass tools are installed at the bottom of a rod pump. On the upward pump stroke, water is
drawn from the casing-tubing annulus into the pump chamber through a set of valves. On the
next downward stroke, these valves close and another set of valves opens, allowing the water to
flow into the tubing. Water accumulates in the tubing until it reaches a sufficient hydrostatic
head so that it can flow by gravity to a disposal formation. The pump provides no pressure for
water injection; water flows solely by gravity. Bypass tools are appropriate for water volumes
from 25 to 250 bbl/d and a maximum depth in the 6,000- to 8,000-ft range. GRI (1999) identified
two vendors of bypass tools: Harbison Fischer and Chriscor, a division of IPEC, Ltd.

Modified plunger rod pump systems incorporate a rod pump, which has its plunger modified to
act as a solid assembly, and an extra section of pipe with several sets of valves located below the
pump. On the upward pump stroke, the plunger creates a vacuum and draws water into the pump
barrel. On the downward stroke, the plunger forces water out of the pump barrel to a disposal
zone. This type of DGWS can generate higher pressure than the bypass tool, which is useful for
injecting into a wider range of injection zones. Modified plunger rod pump systems are better
suited for moderate to high water volumes (250 to 800 bbl/d) and depths from 2,000 to 8,000 ft.
Downhole Separation Technology Performance Page 10

GRI (1999) notes that Downhole Injection, Inc. (DHI) is the leading vendor of modified plunger
rod pump systems, and Burleson Pump reportedly also offered them.

ESPs are commonly used in the petroleum industry to lift fluids to the surface. In a DGWS
application, they can be configured to discharge downward to a lower injection zone. A packer is
used to isolate the producing and injection zones. ESPs can handle much higher flow rates
(greater than 800 bbl/d) and can operate at great depths (more than 6,000 ft). They do require a
substantial supply of electricity that is not always available in the field. ESPs are available from
many suppliers. GRI (1999) reported that Centrilift and REDA (now part of Schlumberger) both
offered DGWS systems using ESPs at that time. GRI also noted that another company, Petrospec
Engineering, Ltd., had introduced an ESP that was deployed on coiled tubing for shallow and
low-power-demand applications. Few ESP-type DGWS tools have been installed.

The fourth type of DGWS uses progressive cavity pumps (also referred to as progressing cavity
pumps). This type of pump has been used throughout the petroleum industry. For DGWS
applications, the pump is configured to discharge downward to an injection zone, or the pump
rotor can be designed to turn in a reversed direction. In an alternate configuration, the
progressive cavity pump can be used with a bypass tool. Then the pump would push water into
the tubing, and the water would flow by gravity to the injection formation. Progressive cavity
pumps can handle solids (e.g., sand grains or scale) more readily than rod pumps or ESPs. GRI
(1999) reported that Weatherford Artificial Lift Systems offered a DGWS system using
progressive cavity pumps. The GRI study did not identify any actual applications of progressive
cavity pump DGWS systems in use.

GRI (1999) gave summary data on 53 DGWS field tests involving 34 operators in the United
States and Canada. Sixty percent of the tests used modified plunger rod pumps, while another
32% used bypass tools. The remaining 8% used ESP systems. Gas production rates were
increased in 57% of the tests, but only 47% of the field tests were termed successful, confirming
that there is still significant risk. About half of the failures were attributed to water cycling or
poor injectivity issues.

Although most DGWS systems are designed for injection to formations below the production
formation, some systems have been developed to inject to a formation that lies above the
production formation.

Recent DGWS Activity

Kudu Industries Inc. provides a downhole water injection tool that relies on a progressing cavity
pump and a Chriscor downhole injection tool. Chriscor Downhole Tools is now a division of
Kudu Industries. The Chriscor tool is installed with a beam pump or a progressive cavity pump
and has a bypass area that allows the water in the tubing string to move downward (Roche 2001).

Quinn Pumps (a division of Quinn’s Oilfield Supply Ltd.) has two DGWS technologies available
(Quinn Pumps Web site [undated]). One is the Q-SepTM Gas T, which pumps water off a gas
well and directly injects the water into a disposal zone in the same well bore. The Q-SepTM Gas
Downhole Separation Technology Performance Page 11

R, which is coupled with a Chriscor injection tool, pumps the water upward, where it flows by
gravity to the injection zone.

Harbison-Fischer Mfg. Co. manufactures a bypass tool licensed from Oxy USA.

DHI continues to develop and test new DGWS equipment. DHI produces rod pumps, including a
reverse flow injection (RFI) system and a progressive cavity RFI system for handling high solids
content. It has pilot-tested a downhole three-phase separation system that is intended to separate
oil, gas, and water into separate streams. As of August 2004, DHI has not yet conducted a full-
scale field test of the three-phase separation system (DHI Web site [undated])

Burleson Pump Company continues to build custom-made plunger pumps for DGWS
applications.

Centrilift remains active in DGWS technology and is marketing an ESP called GasPro™, which
has a capability for controlling the water disposal rate. Centrilift also has a progressing cavity
pump DGWS system (Voss 2004b).

Schlumberger and its REDA Pumps division produce electric submersible pumps and
progressing cavity pumps.

An Austrian company, Rohoel-Aufsuchungs AG, has published two recent papers that briefly
discuss a device called the subsurface side door, or SSD (Clemens and Burgstaller 2004;
Clemens et al. 2004). The lead author of the papers has indicated that the SSD is a simple device
that allows opening or closing a portion of the tubing. It is not a bypass tool; it connects the
producing and injection formations, which are separated by packers (Clemens 2004). The papers
indicate that the field trial in April 2003 was successful and that the company plans a full field
application for 2004.

Dual-Completion Wells

This section describes another technology that can be used to control water in an oil well. The
technology is known as a dual-completion well or a downhole water sink. Oil production can
decline in a well because the oil layer/water layer interface forms a cone around the production
perforations, limiting the volume of oil that can be produced. Downhole water sink technology
requires that an oil well be drilled through the oil-bearing zone to the underlying water zone.
Then the well is completed in both the oil and water zones with the two completions separated
by a packer. During production, oil flows into the top completion while water is drained by the
lower completion. The water drainage rate is adjusted to the oil production rate so that the water
cannot cone upwards and invade the top completion. As a result, the top completion produces
mostly oil with minimal water. The water drained by the lower completion can either be
produced to the surface for treatment or reinjected in the same well.

Dual completion wells have been tested in field operations (Swisher and Wojtanowicz 1995) and
in theoretical studies (Shirman and Wojtanowicz 2000; Wojtanowicz et al. 1999). Swisher
(2000) compares the performance of a dual-completion well with the performance of three wells
Downhole Separation Technology Performance Page 12

having conventional completions in a north Louisiana field. Although the dual-completion well
costs about twice as much to install, it took the same or fewer number of months to reach payout
as did the other wells. At payout, it was producing 55 bbl/d of oil, compared with about 16 bbl/d
produced by the other three wells. The net monthly earnings at payout for the dual-completion
well were nearly $26,000, compared with $5,000–8,000 for the other wells. Wojtanowicz and
Armenta (2004) provide a recent overview of downhole water sink technology, offering a variety
of additional examples from more complicated geologic settings, including gas wells and both
horizontal and vertical oil wells.
Downhole Separation Technology Performance Page 13

Chapter 3 — Data on DOWS and DGWS Installations

As noted in Chapter 1, the purpose of this report is to collect data on as many field installations
of DOWS and DGWS technologies as possible and then try to develop a correlation between
their successful performance and geologic conditions. This chapter provides data on 59 DOWS
and 62 DGWS trials from around the world and a qualitative discussion of at least 35 other
installations. The data are taken from the literature, vendor Web sites, and materials that were
directly provided by operators or vendors. We are aware that there have been other field
installations, but data on those installations are either being held privately as proprietary
information or are not available for other reasons. Despite the fact that they do not include
information on all worldwide field trials, the data compiled here represent the largest and most
complete set of information on downhole separation that is publicly available. We further note
that data are lacking for many trials in some columns of the data tables. Although this lack of
data is unfortunate, the large amount of data that is compiled and reported here is still useful.

The following sections provide general information about the DOWS and DGWS installations. A
discussion of the performance of the installations is included in Chapter 4.

DOWS Installations

Table 1 contains information on 59 DOWS installations. Data on 37 of these installations were

compiled in the original DOWS database in Veil et al. (1999). Data on 13 of the remaining
22 installations came from data summary tables provided by Centrilift (Voss 2004a). The
remaining data were derived from literature published since 1998.

Most of the installations were in North America (34 in Canada and 14 in the United States). Six
were in Latin America, two were in Europe, two were in Asia, and one was in the Middle East.
All trials were at onshore facilities, except for one trial in China. Two-thirds of the installations
used gravity-separation-type DOWS.

DOWS were installed in 24 wells producing from carbonate formations and in 30 wells
producing from sandstone formations. Information on production zone geology was not available
for five other installations. On the injection side, 19 DOWS injected to carbonate formations and
32 injected to sandstone formations. No information was available for eight of the installations.

DGWS Installations

According to one of the companies that has marketed DGWS technology for several years, about
300 systems have been installed in the United States and Canada through 2003 (DHI 2004).
Nevertheless, it was difficult to obtain good data sets on DGWS technology. First of all, very
few papers on DGWS technology have been published in the open literature (e.g., Society of
Petroleum Engineers [SPE] papers). Second, DGWS vendors and users generally have been
reluctant to share the details of their installations. With only a few exceptions, most of the data
compiled on DGWS installations came from a single report (GRI 1999). That report provided
data for many trials but showed only a limited number of parameters for each trial. In addition,
the operators of the wells were not identified. Because of the differences between the GRI data
Downhole Separation Technology Performance Page 14

and the other DGWS data, the data are compiled into separate tables: Table 2 has GRI data, and
Table 3 has other DGWS data.

Table 2 offers limited data on 48 DGWS installations. GRI (1999) contains information on
53 installations, but for five of them, the information was insufficient. Therefore, these were not
included in Table 2. Thirty-four of the installations were in the United States, with Oklahoma
(16) and Kansas (11) heading the list. Fourteen installations were in Alberta. More than 60% of
the installations (30) used modified plunger rod pump systems. Bypass tools were used in
14 installations, and ESPs were used in 4 installations.

DGWS were installed in 11 wells producing from carbonate formations, 12 wells from sandstone
formations, two from clastic formations (combined with sandstone in later analyses), and three
from coal. For 20 other installations, the production zone geology was not stated. On the
injection side, nine DGWS injected to carbonate formations, 13 injected to sandstone formations,
and two injected to clastic formations. No information was available about the remaining 24
installations.

Table 3 shows data on 14 DGWS installations other than those included in Table 2. Eight of
these installations were in Alberta, four were in Oklahoma, and there was one each in Kansas
and Austria. Five of the installations used bypass tools, and five others used modified plunger
rod pump systems. Three used a coil-tubing ESP. The Austrian installation used an SSD device.

DGWS were installed in five wells producing from sandstone formations and two producing
from coal. The production zone geology was not stated for the other seven installations. On the
injection side, five DGWS injected to sandstone formations; no information was available about
the remaining nine installations.

Table 2 shows three installations made into coal-producing formations, and Table 3 shows two
others. None of the five data records identify the operator or well number, but the Table 3
installations may be the same wells as two of the Table 2 installations.

We also obtained limited information from three additional sources about multiple DGWS
installations. None of these data sets was complete enough to include in Table 3. Voss (2004b)
provided a table of 25 Centrilift GASPRO ESP-type DGWS installations from 1993 through
2002. The installations were in Oklahoma, Kansas, Texas, California, and Canada. The table did
not provide information on gas and water production before and after DGWS installation, nor did
it include any description of production or injection formations.

Yu (2004) reported that EnCana Corp. had installed DGWS systems in 10 wells. All were
located in southern Alberta, and all had production from the upper Viking formation (sandstone)
and injection into the lower Viking formation (sandstone). No quantitative performance data
were included.

DHI (undated) has tested DGWS technology in more than 30 wells in the United States and
Canada in a variety of geologic basins ranging from 900 to 6,800 ft in depth. Examples of the
Downhole Separation Technology Performance Page 15

DHI experiences are listed in Table 4. Details on geology, success rate, and equipment type were
not included in DHI (undated).
Downhole Separation Technology Performance Page 16

Chapter 4 — Performance and Relationship to Geologic Conditions

A main goal of this report is to identify trends and correlations between the performances and
probabilities of success of DOWS and DGWS technologies and the geologic conditions in the
production or injection formations.

Previous Analysis

As a starting point, we looked at the conclusions presented at a 2002 meeting of the International
Downhole Processing Group, at which downhole separation experts from around the world
presented their latest information. Alhanati et al. (2002) presented an analysis of the effect of
geologic conditions on the risk of a DOWS trial. Those authors have been involved in
developing some of the hydrocyclone-type DOWS technologies and have followed DOWS
developments for many years. They reviewed records on about 80 installations of hydrocyclone-
type DOWS that used ESPs for pumping. The installations represented 33 wells in 26 fields from
18 different producers.

They concluded that installations having both carbonate production and injection formations
have the lowest risk of failure, or, conversely, the highest probability of success. Installations
having the following production zone/injection zone combinations posed a medium risk:
carbonate/consolidated sandstone, consolidated sandstone/carbonate, and consolidated
sandstone/consolidated sandstone. Installations with carbonate/unconsolidated sandstone or
consolidated sandstone/unconsolidated sandstone conditions posed a medium risk for regular
DOWS installations but a high risk when the injection zone was above the production zone.
Finally, any installation that had unconsolidated sandstone as the production zone offered a high
risk.

Alhanati et al. (2002) does not provide a specific description of how the authors categorized
trials into low, medium, or high risk. It does include summary data on mean time to failure,
percentage increase in oil production, and percentage decrease in water produced to the surface.
Within each of the risk categories, the report does distinguish between weak and strong trials.
Weak trials are those that failed in less than 1 month. Surprisingly, about 41% of the trials in the
low-risk category failed in less than 1 month, although most of the failures were related to
activities not specific to DOWS technology. The low-risk trials clearly stood out in terms of
better mean time to failure, positive impact on oil production, and reduction in water to the
surface. The medium- and high-risk trials were more difficult to segregate, and the primary
factors were the mean time to failure and the number of trials experiencing injectivity problems.

The conclusions of Alhanati et al. (2002) seemed logical, in that sandstone formations are more
likely than carbonate formations to produce solids that will subsequently plug an injection zone.
Unconsolidated sandstone formations are more likely to produce sand grains and other solids
than are consolidated sandstones. Carbonate formations can also contribute small CaSO4 or
CaCO3 scale particulates that can plug injection zones but, in general, sandstone formations will
generate more solids. Although we assumed that the Alhanati et al. (2002) conclusions were
accurate because the researchers used a large data set and had a long history of experience
working with DOWS technology, we still proceeded to independently collect as much data on
Downhole Separation Technology Performance Page 17

DOWS and DGWS trials as possible. The logical place to start was to contact C-FER
Technologies (Alhanati’s organization) to see if we could examine the data that those researchers
used to reach their conclusions. We were advised that C-FER’s data were proprietary and could
not be shared with us. We were further advised that C-FER itself had a difficult time compiling
DOWS data because many of the original records had been archived, key people had left their
positions, and both operator and vendor companies had merged (Zahacy 2004). In the absence of
the original data used by C-FER, we proceeded to collect data from other sources.

Results

Table 5 includes qualitative performance ratings, where possible, for each DOWS installation
listed in Table 1 on overall performance, increase in oil production, reduction in water to the
surface, and longevity of the installation. The following criteria were used to make the
qualitative ratings:

• Increase in oil: good (>20%), neutral (0–20%), and poor (0%),

• Reduction in water: good (>30%) and neutral (0–30%), and
• Longevity: good (>3 months) and neutral (0–3 months).

The overall rating was a subjective, qualitative evaluation of the three specific ratings. This
ranking scheme has shortcomings, but we were unable to provide a more precise ranking scheme
because there were gaps in the available data. Because few of the records in Table 1 had both
start and end dates, it was often difficult to determine the longevity of an installation or its mean
time to failure. Another complicating factor is that most of the data records we obtained express
“before-DOWS performance” and “after-DOWS performance” in terms of a single number. We
evaluated a few detailed data sets (Veil 2000; Argonne and ALL-LLC 2001) and found that oil
and water production vary significantly over time and also vary as the mechanical features of the
pumping system (e.g., pump rates, pressures) are tweaked by the operators. Many of the
installations included in Table 1 were at least partially experimental in nature so that the
operators and vendors could determine how well the technology performed under different
conditions. We were unable to determine how representative of long-term operation the single-
number performance values were.

Table 2 summarizes DGWS data from GRI (1999). We do not have much information on the
trials themselves. GRI included its own performance ranking of success, failure, or economic
failure. GRI (1999) notes that a ranking of success is generally associated with mechanical or
technical success, an increase in gas production, or a decreased cost compared to handling water
at the surface. GRI further notes that an increase in gas production is not the only criterion
considered and that not all successful installations showed an increase in gas production. It
reports that failures were associated with difficulty in injecting the water, low gas rates, or poor
well bore conditions.

Table 3 contains information on a few additional DGWS installations not included in GRI
(1999). Because the data records are not complete, only an overall performance rating is shown.
The data records in Table 3 are generally less complete than those in Table 1, so it was even
more difficult to assign a meaningful performance ranking. In about half of the installations, the
Downhole Separation Technology Performance Page 18

wells in which the DGWS were installed were shut in before the installation. Any increase in gas
production could be viewed as a positive trial. For all other installations in Table 3, the gas
production increased following installation, so all trials were rated as good except for two that
were considered uneconomical by the operators. These were given a ranking of neutral, because
they were achieving DGWS goals but had low gas production attributed to various factors.

Table 6 compares qualitative performance with geologic types for the 59 DOWS installations
from Table 1. Overall, about 59% of the trials were rated as good. All three categories in which
both the production and injection formations were known showed about the same percentage of
good trials (50–58%). Overall, about 31% of the trials were rated as poor. For the three
categories in which both the production and injection formations were known, the percentage of
poor trials ranged from 28% for sandstone/sandstone to 50% for carbonate/sandstone.

The results from Table 2 installations are tallied in Table 7, which compares GRI’s qualitative
performance with geologic types for 48 DGWS installations. Overall, about 54% of the trials
were rated as successes. Note that this is a similar percentage to that shown in Table 6 for the
DOWS trials. The carbonate/carbonate, carbonate/sandstone, and sandstone/sandstone categories
all showed a high percentage of trials that were successes (70–100%), but none of the three stood
out as being a clearly better combination than the others. Overall, about 42% of the trials were
rated as failures or economic failures. Nearly half of the trials were in situations in which either
one or both of the formations were unknown. This subset of trials had the worst overall success
rate, with only 30% being rated successes and 61% being rated as failures or economic failures.

The results from Table 3 are much more straightforward; no additional tabulation is necessary.
Twelve of the 14 trials were qualitatively rated as being good. Five trials had
sandstone/sandstone formations, and two others had coal/unknown formations. No information
on formations was available for the other seven trials.

The previous chapter mentioned additional but incomplete data on Centrilift and EnCana
installations. Voss (2004b) noted that out of 25 Centrilift DGWS installations, 20 met or
exceeded economic and performance criteria, four met pumping expectations but did not produce
economical gas volumes, and only one failed. The failed installation was determined to be
undersized and unable to meet pumping performance. Voss does not include information on the
geology of the production or injection formations, so no correlations were possible for this set of
installations.

Yu (2004) noted that his company’s 10 DGWS trials worked to some degree. The results were
very site specific. Successful performance depended more on the ability of the injection
formation to take the water (i.e., injectivity) than on any particular type of geology. He further
noted that trials could have problems with sand. This is not surprising, given that all trials had
both sandstone production and injection formations.
Downhole Separation Technology Performance Page 19

Chapter 5 — Conclusions

Is There a Relationship between DOWS and DGWS Success and Geologic Conditions?

Alhanati et al. (2002) draws clear conclusions on the relationship between DOWS performance
and geologic conditions. In particular, the paper suggests that the combination of carbonate
production and carbonate injection formations offers the lowest risk and, therefore, the highest
chance of DOWS success. Unfortunately, the researchers did not make their raw data available
for others to review.

An independent analysis of about 120 DOWS and DGWS installations in numerous countries,
states, and provinces does not show the same relationship. On the basis of the data described in
this report, it is not possible to predict the performance or likelihood of DOWS or DGWS
success solely on the basis of the geology of the production or injection formation. One caveat to
this conclusion is that the data sets reviewed by Alhanati and his coauthors were probably much
more complete than the data sets presented in this report. We believe that our conclusions are
still valid but recognize that we limited our analysis solely to rock type and did not consider a
wide range of geologic properties in our ranking scheme. Despite intensive efforts to obtain more
complete data sets, we were unsuccessful in that regard.

What Factors Should Be Considered in Siting DOWS or DGWS Installations?

Other factors can play a role in the success of DOWS systems. Veil et al. (1999) reviews some
characteristics of good candidate wells.

• Probably the most important factor is that the injection formation has good injectivity. A
step rate injection test can be performed to determine at what pressure and rate the
disposal zone takes water and at what point the injection zone clogs or fractures.

• A related factor is that the injection process should not introduce materials that could clog
the pores of the injection formation and reduce its injectivity. Several factors are relevant
to clogging. Solid particles could come from the production formation, from proppants
used in hydraulic fracturing, or from chemical precipitates or biological slimes created by
interactions between the water from production formations and the water from injection
formations. Small amounts of oil in the produced water can potentially serve to block
pores because of capillarity effects. It may be important to include a pretreatment
process that produces a water stream that is extremely low in colloidal oil content
(globules 5 to 50 µm in size).

• Another important parameter is good vertical and mechanical separation between the
production and injection formations.

• The candidate well should be located in a reservoir that has sufficient remaining reserves
to allow payback of the investment.
Downhole Separation Technology Performance Page 20

Representatives from companies that have used or have sold DGWS technologies were contacted
and asked their opinion on the value of the geologic setting and other factors (Yu 2004; White
2004; Tortensen 2004; Prostebby 2004). A theme that emerged from these discussions was that
the DGWS success rate is not dependent on the geology of the source zone or disposal zone but
rather on site-specific properties of the disposal zone at individual wells. In general, a high-
permeability, high-porosity, fractured, and underpressured disposal zone is favorable for DGWS
technology.

Why Haven’t DOWS and DGWS Technologies Been Used More Often?

Many of the early trials were made in poorly chosen candidate wells. Companies often offered
wells near the end of their useful lives for trials rather than wells that had a good chance of
success. In some cases, equipment suppliers designed and installed systems on the basis of
formation data supplied by operators. The data were not always accurate, and the systems failed
because they were designed for conditions other than those actually present in the formation.

In many of the DOWS and DGWS installations, individual components of the system that were
not unique to DOWS or DGWS technologies failed prematurely. For example, a cable may have
been crimped during installation, a bolt may not have been fastened tightly, pump motors may
have shorted out, or seals might have leaked. These types of problems have plagued many
DOWS and DGWS installations, and in the past few years, operators have been reluctant to
make new DOWS or DGWS installations.

What Is the Value of This Report?

This report was not able to meet the goal outlined by the DOE project manager (i.e., determining
the geologic conditions that most favor DOWS and DGWS success and identifying the fields and
formations throughout the United States that have that preferred geology). In order to make that
type of analysis, detailed information on the geological properties of the formations (e.g.,
injectivity, permeability, extent of fracturing, vertical separation between production and
injection formations, fracture pressure) and more accurate information on the longevity of
successful operation of the technology and the reasons for failure or termination of the trials
would be needed. Those data either do not exist or have not been made available for the
purposes of this analysis.

In spite of these shortcomings, the report is valuable because it contains the most complete
publicly available set of data on DOWS and DGWS installations. The data tables and list of
references contained herein represent a useful resource for other researchers and scholars.
Downhole Separation Technology Performance Page 21

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Downhole Separation Technology Performance Page 23

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Downhole Separation Technology Performance Page 24

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Downhole Separation Technology Performance Page 25

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Smestad, P., 2004, personal communication between Smestad (READ Well Services, Oslo,
Norway) and J. Veil (Argonne National Laboratory, Washington, DC), March 5.

Stuebinger, L., 1998, personal communication between Stuebinger (Texaco, Denver, CO) and
B. Langhus (CH2M HILL, Tulsa, OK), July 15.

Swisher, M., 2000, “Summary of DWS Application in Northern Louisiana,” presented at

Downhole Water Separation Technology Workshop, Baton Rouge, LA, March 2.

Swisher, M.D., and A.K. Wojtanowicz, 1995, “New Dual Completion Method Eliminates
Bottom Water Coning,” SPE 30697, presented at 1995 SPE Annual Technical Conference and
Exhibition, Dallas, TX, October 22–25.

Tortensen, B., 2004, personal communication between Tortensen (Addison Energy, Calgary,
Alberta, Canada) and J. Quinn (Argonne National Laboratory, Argonne, IL), July 2.

Veil, J.A., 2000, Summary of Data from DOE-Subsidized Field Trial #1 of Downhole Oil/Water
Separator Technology — Texaco Well Bilbrey 30 — Federal No. 5, Lea County, New Mexico,
prepared for U.S. Department of Energy, National Petroleum Technology Office, May. Available
at http://www.ead.anl.gov/pub/dsp_detail.cfm?PubID=1221.

Veil, J.A., 2001 “Interest Revives in Downhole Oil/Water Separators,” Oil & Gas Journal,
pp. 47–56, Feb. 26.

Veil, J.A., 2003, “An Overview of Applications of Downhole Oil/Water Separators,” presented
at the Produced Water Workshop, Aberdeen, Scotland, March 26–27.

Veil, J.A., B.G. Langhus, and S. Belieu, 1999, Feasibility Evaluation of Downhole Oil/Water
Separation (DOWS) Technology, prepared by Argonne National Laboratory, CH2M-Hill, and
Nebraska Oil and Gas Conservation Commission for the U.S. Department of Energy, Office of
Fossil Energy, National Petroleum Technology Office, Jan. Available at http://www.ead.anl.
gov/pub/dsp_detail.cfm?PubID=416.
Downhole Separation Technology Performance Page 26

Veil, J.A., M.G. Puder, D. Elcock, and R.J. Redweik, Jr., 2004, “A White Paper Describing
Produced Water from Production of Crude Oil, Natural Gas, and Coal Bed Methane,” prepared
by Argonne National Laboratory, Argonne, IL, for the U.S. Department of Energy, National
Energy Technology Laboratory, Jan. Available at http://www.ead.anl.gov/pub/dsp_detail.
cfm?PubID=1715.

Verbeek, P.H.J., and C. Wittfeld, 2004, “Downhole/Water Separation: Technical and Economic
Perspectives,” presented at the Second Produced Water Workshop, Aberdeen, Scotland,
Apr. 21–22.

Verbeek, P.H.J., R.G. Smeenk, and D. Jacobs, 1998, “Downhole Separator Produces Less Water
and More Oil,” SPE 50617, presented at the 1998 SPE European Petroleum Conference, The
Hague, Netherlands, Oct. 20–22.

Voss, D., 2004a, electronic mail with attached table entitled “Downhole Oil/Water Separation
(DHOWS) History,” from Voss (Baker Hughes Centrilift, Claremore, OK) to J. Veil (Argonne
National Laboratory, Washington, DC), March 3.

Voss, D., 2004b, electronic mail with attached table entitled, “GASPRO Performance
Summary,” from Voss (Baker Hughes Centrilift, Claremore, OK) to J. Quinn (Argonne National
Laboratory, Argonne, IL), July 22.

Walker, J.F., and R.L. Cummins, 1999, “Development of a Centrifugal Downhole Separator,”
OTC #11031, presented at the Offshore Technology Conference, Houston, TX, May 3–6.

White, B., 2004, personal communication between White (Anadarko Petroleum Corporation,
Houston, TX) and J. Quinn (Argonne National Laboratory, Argonne, IL), July 2 and 6.

Wojtanowicz, A.K., and M. Armenta, 2004, “Petroleum Wells with Controlled Water Inflow —
Downhole Water Sink Technology,” presented at Second Produced Water Workshop, Aberdeen,
Scotland, April 21–22.

Wojtanowicz, A.K., E.I. Shirman, and H. Kurban, 1999, “Downhole Water Sink (DWS)
Completions Enhance Oil Recovery in Reservoirs with Water Coning Problem,” SPE 56721,
presented at the SPE Annual Technical Conference and Exhibition, Houston, TX, Oct. 3–6.

Wright, J., 1998, personal communication between Wright (Talisman Energy, Calgary, Alberta,
Canada) and B. Langhus (CH2M HILL, Tulsa, OK), March.

Yu, M., 2004, personal communication between Yu (EnCana Corp., Calgary, Alberta, Canada)
and J. Quinn (Argonne National Laboratory, Argonne, IL), July 2.

Zahacy, T., 2004, personal communication between Zahacy (C-FER Technologies, Edmonton,
Alberta, Canada) and J. Veil (Argonne National Laboratory, Washington, DC), March 26.
Table 1 - Data on DOWS Installations (Note that data for each installation spans two sheets) Page 1 of 10
Post-
Pre-DOWS Post- DOWS
Operator and Well State/ Type of Pre-DOWS Water DOWS Oil Water % Increase in % Decrease Casing Production Injection
Name Field Province DOWS Oil (bpd) (bpd) (bpd) (bpd) Oil in Water Size (in.) Formation Formation
Imperial Redwater Redwater Alberta Aqwanot
TM 19 1,780 24 59 26 97 7 Devonian D- Devonian D-
#1-26 3 3
Pinnacle-Alliance Alliance Alberta AqwanotTM 44 380 100 95 127 75 5.5 Ellerslie- Dina
(originally Dina
PanCanadian) 7C2
Pinnacle-Alliance Alliance Alberta AqwanotTM 25 820 100 160 300 80 5.5 Ellerslie- Dina
(originally Dina
PanCanadian) 06D
Pinnacle-Alliance Alliance Alberta AqwanotTM 38 1,200 37 220 -3 82 5.5 Ellerslie- Dina
(originally Dina
PanCanadian) 07C
Texaco Dickson #17 East Texas Texas DAPS 3 184 10 126 233 32 7 Woodbine

PanCanadian 00/11C-05 Provost Alberta AqwanotTM 21 690 17 -19 5.5 Dina

PanCanadian 00/11A2- Provost Alberta AqwanotTM 34 979 14 -59 7 Dina

05
PanCanadian 00/16-05 Provost Alberta AqwanotTM 9.4 546 16 70 5.5 Dina

Texaco SU 1040 Levelland Texas DAPS

Talisman Energy 4-27-9- Parkman Saskatch- AqwanotTM 6 629 39 21 550 97 7

33W1 ewan
PanCanadian 00/02-09 Bashaw Alberta AqwanotTM 13 428 164 239 1162 44 5.5 Nisku D-2 Nisku D-3

Talisman Energy Parkman Saskatch- DAPS 16 252 33 139 106 45 5.5 Tilston Lower
Tidewater Parkman 4- ewan Tilston
27
Anderson 08-17 Swan Hills Alberta Aqwanot
TM 176 3,648 264 264 50 93 7 Beaverhill Beaverhill
Unit #1 Lake Lake

Texaco Salem #85-40 Salem Illinois DAPS 6 655 6 150 0 77 5.5 Salem Devonian

Chevron Fee 153X Rangely Colorado Aqwanot

TM 45 1,400 32 500 -29 64 7 Weber Zone Weber Zone
1&3 5
Table 1 - Data on DOWS Installations (Note that data for each installation spans two sheets) Page 2 of 10
Injection Prod. and Inj.
Pressure Formation Trial Trial
Operator and Well Injectivity Differential Separation Starting Ending Source of
Name Lithology (bpd/psi) (psi) (ft) Date Date Comments Information
Imperial Redwater Carbonate/ Jul-94 Jan-95 Scale problems. Gray (1998)
#1-26 carbonate
Pinnacle-Alliance Sandstone/ 20 0 43 Jul-95 Matthews et
(originally sandstone al. (1996)
PanCanadian) 7C2
Pinnacle-Alliance Sandstone/ 2 0 73 Aug-95 Matthews et
(originally sandstone al. (1996)
PanCanadian) 06D
Pinnacle-Alliance Sandstone/ 20 0 60 Sep-95 Matthews et
(originally sandstone al. (1996)
PanCanadian) 07C
Texaco Dickson #17 Sandstone/ Oct-95 Shut in. Elphingstone
sandstone (1998)
PanCanadian 00/11C-05 Sandstone/ Dec-95 Problems with sand Florence
sandstone plugging. (1998)
PanCanadian 00/11A2- Sandstone/ Dec-95 Problems with sand Florence
05 sandstone plugging. (1998)
PanCanadian 00/16-05 Sandstone/ Jan-96 Problems with sand Florence
sandstone plugging. (1998)
Texaco SU 1040 Sandstone Feb-96 Pulled early. Elphingstone
(1998)
Talisman Energy 4-27-9- Carbonate/ May-96 Naylor (1998)
33W1 carbonate
PanCanadian 00/02-09 Carbonate/ 104 May-96 Problems with H2S and Florence
carbonate scale. (1998)
Talisman Energy Carbonate/ 6 0 Jul-96 May-97 Corrosion problems to Wright (1998)
Tidewater Parkman 4- carbonate pump and tubing.
27
Anderson 08-17 Carbonate/ 21 0 23 Jul-96 Problems with well Peats (1998)
carbonate bore and scale
formation.
Texaco Salem #85-40 Carbonate/ 1,137 Aug-96 Apr-97 Pumps damaged by Murphy
unknown corrosion. (1998)
Chevron Fee 153X Sandstone/ 0 30 Aug-96 May have been Hild (1997)
sandstone recycling water?
Undersized pump.
Table 1 - Data on DOWS Installations (Note that data for each installation spans two sheets) Page 3 of 10
Post-
Pre-DOWS Post- DOWS
Operator and Well State/ Type of Pre-DOWS Water DOWS Oil Water % Increase in % Decrease Casing Production Injection
Name Field Province DOWS Oil (bpd) (bpd) (bpd) (bpd) Oil in Water Size (in.) Formation Formation
Talisman Energy Creelman Saskatch- Aqwanot
TM 113 2,516 277 126 145 95 7 Alida Alida
Creelman 3c7-12/dB ewan

Chevron Shepard #65 East Texas Texas DAPS 7 269 16.5 127 136 53 5.5 Woodbine Woodbine

Richland Parkman 1-17 Parkman Saskatch- DAPS 20 220 15 190 -25 14 5.5 Tilston Souris River
ewan

Texaco RMOTC 77 RMOTC Wyoming DAPS 5 190 10 38 100 80 5.5 2nd Wall 3rd Wall
Ax20 Creek Creek

Talisman Energy Hayter Chatwin Alberta DAPS 25 250 32 25 28 90

Talisman Energy Hands- Saskatch- Hydro-Sep 88 1,700 50 189 -43 89 7 Alida Blairmore
Handsworth 4dB- worth ewan
16/1d6
Talisman Energy South Grande Alberta DAPS 27 932 26 179 -4 81
Sturgeon Prairie
Petro-Canada E4-10-16 Bellshill Alberta Q-Sep-G 30 470 38 61 27 87 7 Basal Basal
Lake Quartz Quartz
Chevron PNB 14-20 Drayton Alberta DAPS 75 517 84 14 12 97 5.5 Nisku D2 Nisku D3
Valley

Wascana B7-27 South Saskatch- Aqwanot

TM 76 2,450 0 380 -100 84 7 Upper Lower
Success ewan Rosary Rosary

PT Caltex Pacific 5E83 Minas Indonesia Aqwanot

TM 631 7,060 14 1,153 -98 84 7

Petro-Canada Utik 13- Utikuma Alberta DAPS 8 451 10 63 25 86 5.5 Keg River Keg River
21

Marathon Etah #7 Garland Wyoming Hydro-Sep 70 4,000 78 320 11 92 8.625 Madison Madison
Table 1 - Data on DOWS Installations (Note that data for each installation spans two sheets) Page 4 of 10
Injection Prod. and Inj.
Pressure Formation Trial Trial
Operator and Well Injectivity Differential Separation Starting Ending Source of
Name Lithology (bpd/psi) (psi) (ft) Date Date Comments Information
Talisman Energy Carbonate/ 0 Aug-96 Sobie and
Creelman 3c7-12/dB carbonate Matthews
(1997)
Chevron Shepard #65 Sandstone/ 0 71 Sep-96 Unit is currently due Noonan
sandstone for a workover but has (1998);
functioned well. Roberts
(1998)
Richland Parkman 1-17 Carbonate/ 13 40 151 Jan-97 Immediately after Scharrer
carbonate installation, well (1998)
produced 35 bpd oil
and 160 bpd water.
Texaco RMOTC 77 Sandstone/ 240 Feb-97 Mar-97 Injection zone damaged Stuebinger
Ax20 sandstone during a workover. (1998)

Talisman Energy Hayter Sandstone Feb-97 Wright (1998)

Talisman Energy Carbonate/ 34 -412 1,284 Apr-97 Sobie and

Handsworth 4dB- sandstone Matthews
16/1d6 (1997)
Talisman Energy South Carbonate/ May-97 Wright (1998)
Sturgeon carbonate
Petro-Canada E4-10-16 Sandstone/ 100 81 May-97 Nov-97 Worked very well; sold McIntosh
sandstone lease. (1998)
Chevron PNB 14-20 Carbonate/ May-97 Aug-97 Well was very unstable Lockyer
carbonate and gassy; DAPS (1998)
worked well.
Wascana B7-27 Sandstone/ Very high 12 May-97 Nov-97 Produced sand Briffet (1998)
sandstone damaged the
hydrocyclone.
PT Caltex Pacific 5E83 Sandstone/ May-97 Jun-97 Packer leak. Voss (2004a)
sandstone
Petro-Canada Utik 13- Sandstone/ 46 Jun-97 Oct-97 After two days, DAPS Krug (1998)
21 sandstone stopped working.
DAPS was set above
the fluid level.

Marathon Etah #7 Carbonate/ 20 300 48 Jun-97 Did not install check Kintzele
carbonate valve. (1997)
Table 1 - Data on DOWS Installations (Note that data for each installation spans two sheets) Page 5 of 10
Post-
Pre-DOWS Post- DOWS
Operator and Well State/ Type of Pre-DOWS Water DOWS Oil Water % Increase in % Decrease Casing Production Injection
Name Field Province DOWS Oil (bpd) (bpd) (bpd) (bpd) Oil in Water Size (in.) Formation Formation
Texaco Ingram East Texas Texas DAPS 15 26 150 73 7 Woodbine

Gulf Canada 02/12-01 Fenn-Big Alberta AqwanotTM 21 1,038 117 217 457 79 7 Nisku D-2 Nisku D-3
Valley
Tristar Sylvan Alberta DAPS 35 403 57 86
Lake

Talisman Energy 7d9- Hands- Saskatch- Subsep 94 1,560 133 586 41 62 7

6/1-6-10-7w2m worth ewan
Crestar Energy Sylvan Alberta DAPS 25 315 2 54 -92 83 5.5 Pekisko Pekisko
Ranchman Sylvan Lake Lake
00/08

Talisman Energy Hands- Saskatch- Aqwanot

TM 63 1,260 38 63 -40 95 7 Alida Blairmore
Handsworth 2d5-13/1c7 worth ewan

Shell International Eldingen Germany AqwanotTM 10 470 31 168 210 64 6.625 Top Lias Top Lias
Eldingen 58 Alpha Alpha
Tri-Link Resources Bender Saskatch- Progressing 35 976 35 227 0 77 5.5 Tilston Souris
Bender 9-30 ewan cavity version Valley
of
hydrocyclone-
type DOWS

PanCanadian 00/07-09 Bashaw Alberta Hydro-Sep 19 352 62 250 226 29 5.5 Nisku D-2 Nisku D-3
Bashaw
Southward 11-13 Carlile Saskatch- DAPS 24.5 458 16 -35 5.5 Tilston Souris River
ewan

Pioneer Resources 5b- David, Alberta Subsep 53 2,994 80 150 51 95 5.5

25-040-03 Dina
Astra VM-097 La Ventana Argentina SubSep 57 2,463 41 567 -28 77 5.5 Barrancas Rio Blanco
Table 1 - Data on DOWS Installations (Note that data for each installation spans two sheets) Page 6 of 10
Injection Prod. and Inj.
Pressure Formation Trial Trial
Operator and Well Injectivity Differential Separation Starting Ending Source of
Name Lithology (bpd/psi) (psi) (ft) Date Date Comments Information
Texaco Ingram Sandstone/ Jul-97 Elphingstone
sandstone (1998)
Gulf Canada 02/12-01 Carbonate/ 23 0 148 Jul-97 Peats (1998)
carbonate
Tristar Carbonate/ Jul-97 Company out of Poythress
carbonate business; disposition of (1998)
well is unknown.
Talisman Energy 7d9- Carbonate/ Jul-97 Dec-97 Injection zone sanded Voss (2004a)
6/1-6-10-7w2m sandstone up.
Crestar Energy Carbonate/ 24 Crestar Aug-97 Mar-98 Water is recycling; Grenier
Ranchman Sylvan Lake carbonate Energy separation of zones is (1998)
00/08 Ranchman only 24 feet in a
Sylvan Lake fractured carbonate.
00/08
Talisman Energy Carbonate/ 43 Aug-97 Capillary tube got Sobie and
Handsworth 2d5-13/1c7 carbonate creased. Matthews
(1997)
Shell International Sandstone/ 89 Sep-97 Mar-00 Verbeek et al.
Eldingen 58 sandstone (1998)
Tri-Link Resources Carbonate/ 87 76 Oct-97 Mar-98 Pulled DOWS because Browning
Bender 9-30 carbonate of failure in transfer (1998)
tube.

PanCanadian 00/07-09 Carbonate/ 133 Nov-97 Florence

Bashaw carbonate (1998)
Southward 11-13 Carbonate/ Jan-98 Mar-98 Residence time in Poythress
carbonate separation chamber (1998)
was too short; oil lost
into disposal zone.
Pioneer Resources 5b- Sandstone/ Apr-98 Injection zone sanded Voss (2004a)
25-040-03 sandstone up.
Astra VM-097 Sandstone/ Apr-98 Nov-98 Injection zone sanded Scaramuzza et
sandstone up. al. (2001)
Table 1 - Data on DOWS Installations (Note that data for each installation spans two sheets) Page 7 of 10
Post-
Pre-DOWS Post- DOWS
Operator and Well State/ Type of Pre-DOWS Water DOWS Oil Water % Increase in % Decrease Casing Production Injection
Name Field Province DOWS Oil (bpd) (bpd) (bpd) (bpd) Oil in Water Size (in.) Formation Formation
Chevron HSA #1107 Wickett Texas Hydro-Sep Wichita- Wichita-
Albany Albany

PanCanadian 4C-33-40- Hayter Alberta Aqwanot

TM 28 1,387 25 352 -11 75 7
1W4
Marathon Colony Fee Wyoming Subsep 86 7,692 47 567 -45 93 7
16
Elf LaqSup 90 LaqSup France Subsep 19 961 31 16 63 98 9.625 Lower
Senonien
Spirit Energy Van Texas AqwanotTM 62 3,402 71 167 15 95 5.5

Marathon IHU-12 Indian Hills New Aqwanot

TM 560 7,440 560 560 0 92 7
Mexico
Texaco Bilbrey 30 -Fed. Lost Tank New TAPS 17 173 7 70 -59 60 5.5 Lower Bell Canyon
No. 5 Delaware Mexico Cherry
Canyon
Astra VI-284 Vizca- Argentina Subsep 18 1,052 18 265 0 75 5.5 Papagayos Barrancas
cheras
Astra VI-261 Vizca- Argentina Subsep 51 1,408 51 117 0 92 5.5 Papagayos Barrancas
cheras
Phillips XJ30-2 Xijiang China Subsep 1,903 6,747 2,200 1,800 16 73 9.625
platform
PDO Y-276 Yibal Oman AqwanotTM 462 3,840 708 954 53 75 9.625

Repsol/YPF Amo C-1 Tivacuno Ecuador Subsep 636 8,964 275 2,800 -57 69 9.625
EnCana 13W4 Schneider Alberta Subsep 118 668 118 118 0 82 7
Lake
PDVSA La Victoria Venezuela Read 300 8,000 800 3,700 167 54

EnCana 21W4 Wayne Canada Subsep 57 2,295 57 138 0 94 5.5

Rosedale
Astra VI-122 Vizca- Argentina Subsep 38 1,972 38 254 0 87 5.5
cheras
Table 1 - Data on DOWS Installations (Note that data for each installation spans two sheets) Page 8 of 10
Injection Prod. and Inj.
Pressure Formation Trial Trial
Operator and Well Injectivity Differential Separation Starting Ending Source of
Name Lithology (bpd/psi) (psi) (ft) Date Date Comments Information
Chevron HSA #1107 Carbonate/ Jul-98 Permit assigned, Noonan
carbonate waiting on tools. (1998);
Roberts
(1998)
PanCanadian 4C-33-40- Sandstone/ Aug-98 Voss (2004a)
1W4 sandstone
Marathon Colony Fee Carbonate/ Sep-98 Jan-00 Motor burned up. Voss (2004a)
16 sandstone
Elf LaqSup 90 Carbonate/ Oct-98 May-01 Test concluded. Chapuis et al.
sandstone (1999)
Spirit Energy Sandstone/ Oct-98 Injection zone sanded Voss (2004a)
sandstone up.
Marathon IHU-12 Sandstone/ Oct-98 Casing failure. Voss (2004a)
sandstone
Texaco Bilbrey 30 -Fed. Sandstone/ 480 Jan-99 Aug-99 Well sold; DOWS Veil (2000)
No. 5 sandstone pulled.

Astra VI-284 Sandstone/ Feb-99 Nov-00 Scaramuzza et

sandstone al. (2001)
Astra VI-261 Sandstone/ Jul-99 Oct-00 Motor burned up. Scaramuzza et
sandstone al. (2001)
Phillips XJ30-2 Sandstone/ Sep-00 Oct-00 Water recirculation. Voss (2004a)
sandstone
PDO Y-276 Unknown Feb-01 Mar-01 Motor drive failed. Verbeek and
Wittfeld
(2004)
Repsol/YPF Amo C-1 Unknown Apr-01 Apr-02 Motor burned up. Voss (2004a)
EnCana 13W4 Unknown May-01 Dec-03 Voss (2004a)

PDVSA Unknown Dec-01 May-02 Failure of cable, pump, Bangash and

and pressure gauges. Reyna (2003);
Smestad
(2004)

EnCana 21W4 Unknown Jun-02 Dec-03 Voss (2004a)

Astra VI-122 Sandstone/ Oct-02 May-03 Voss (2004a)

sandstone
Table 1 - Data on DOWS Installations (Note that data for each installation spans two sheets) Page 9 of 10
Post-
Pre-DOWS Post- DOWS
Operator and Well State/ Type of Pre-DOWS Water DOWS Oil Water % Increase in % Decrease Casing Production Injection
Name Field Province DOWS Oil (bpd) (bpd) (bpd) (bpd) Oil in Water Size (in.) Formation Formation
Renaissance Energy Provost Alberta Q-Sep-G 13 252 18 60 38 76 Dina Dina

Rennaissance Energy Webb Saskatch- Q-Sep-G 50 441 37 69 -26 84 Roseray Roseray

South ewan
Santa Fe Energy Jones Indian New TM
Aqwanot 100 3,000 7 Cisco- Devonian &
Canyon 4-#2 Basin Mexico Canyon Montoya
Table 1 - Data on DOWS Installations (Note that data for each installation spans two sheets) Page 10 of 10
Injection Prod. and Inj.
Pressure Formation Trial Trial
Operator and Well Injectivity Differential Separation Starting Ending Source of
Name Lithology (bpd/psi) (psi) (ft) Date Date Comments Information
Renaissance Energy Sandstone/ Injection zone plugged. Quinn Pumps
sandstone website
Rennaissance Energy Sandstone/ Plugged with sand. Quinn Pumps
sandstone website
Santa Fe Energy Jones Carbonate/ 212 2,300 Permitted. Rogers (1997)
Canyon 4-#2 carbonate
 Table 2 - DGWS Installation Data from GRI (1999) Page 1 of 3

Pre- GRI's
State/ DGWS Post- Post-DGWS Qualitative
Province/ Pre-DGWS Water DGWS Water % Increase Injection Measure of
Country Type of DGWS Gas (mcfd) (bpd) Gas (mcfd) Injected (bpd) in Gas Production Formation Lithology Formation Lithology Performance
Alberta Bypass seating nipple, Shut in Shut in 175 Lower Cretaceous Clastics Lower Clastics Success
Harbison Fischer Cretaceous

Alberta Bypass seating nipple, Shut in Shut in 150 Lower Cretaceous Clastics Lower Clastics Success
Harbison Fischer Cretaceous

OK Bypass seating nipple, 125 130 200 130 60 Cottage Grove Sandstone Wabaunesee/ Sandstone Success
Harbison Fischer Lower Council
Grove
OK Bypass seating nipple, Shut in 250 220 250 Council Grove (Wolfcampian) Shallow shelf Lower Council Shallow shelf Success
Harbison Fischer (before carbonate Grove carbonate
shut in)
OK Bypass seating nipple, 0 250 160 250 Council Grove (Wolfcampian) Shallow shelf Lower Council Shallow shelf Success
Harbison Fischer carbonate Grove carbonate

OK Bypass seating nipple, Shut in Shut in 90 250 Council Grove (Wolfcampian) Shallow shelf Lower Council Shallow shelf Success
Harbison Fischer carbonate Grove carbonate

OK Bypass seating nipple, 50 15 18 300 -64 Council Grove (Wolfcampian) Shallow shelf Lower Council Shallow shelf Failure
Harbison Fischer carbonate Grove carbonate

TX Bypass seating nipple, 140 70 100 70 -29 Council Grove (Wolfcampian) Shallow shelf Lower Council Shallow shelf Success
Harbison Fischer carbonate Grove carbonate

Alberta Downhole water Shut in Shut in 706 143 Manneville Sands Manneville Sands Success
injection tool (Chriscor)

Alberta Downhole water Shut in Shut in 353 142 Manneville Sands Manneville Sands Success
injection tool (Chriscor)

Alberta Downhole water Shut in Shut in 353 238 Manneville Sands Manneville Sands Success
injection tool (Chriscor)

Alberta Downhole water Shut in Shut in 282 87 Manneville Sands Manneville Sands Success
injection tool (Chriscor)

Alberta Downhole water Shut in Shut in 194 244 Manneville Sands Manneville Sands Success
injection tool (Chriscor)

Alberta Downhole water Shut in Shut in 141 71 Manneville Sands Manneville Sands Success
injection tool (Chriscor)

OK Electric submersible 200 1,500 200 10,000 0 Economic failure

pump (Centrilift and
Reda)
OK Electric submersible 120 1,500 120 1,500 0 Morrow Sandstone Economic failure
pump (Centrilift and
Reda)
 Table 2 - DGWS Installation Data from GRI (1999) Page 2 of 3

Pre- GRI's
State/ DGWS Post- Post-DGWS Qualitative
Province/ Pre-DGWS Water DGWS Water % Increase Injection Measure of
Country Type of DGWS Gas (mcfd) (bpd) Gas (mcfd) Injected (bpd) in Gas Production Formation Lithology Formation Lithology Performance
Alberta Electric submersible Shut in Shut in 100 NA Success
pump (Petrospec coiled
tubing)
Alberta Electric submersible 350 220 990 200 183 Success
pump (Petrospec coiled
tubing)
OK Modified plunger rod 50 290 Mulky Coal Burgess Sandstone Failure
pump (DHI)
OK Modified plunger rod Shut in Shut in 24 140 Mulky Coal Burgess Sandstone Success
pump (DHI)
OK Modified plunger rod Shut in Shut in 20 50 Mulky Coal Burgess Sandstone Failure
pump (DHI)
KS Modified plunger rod New well 450 175 250 Viola Dolomite Arbuckle Dolomite Success
pump (DHI)
KS Modified plunger rod 102 66 160 100 57 Chase (Upper Wolfcampian) Dolomite/limestone Chester and Sandstone Success
pump (DHI) Morrow
KS Modified plunger rod 133 50 160 90 20 Chase (Upper Wolfcampian) Dolomite/limestone Council Grove Shallow shelf Success
pump (DHI) (Wolfcampian) carbonate
KS Modified plunger rod NA 125 103 135 Chase (Upper Wolfcampian) Dolomite/limestone Council Grove Shallow shelf Failure
pump (DHI) (Wolfcampian) carbonate
KS Modified plunger rod Shut in 50 60 50 Chase (Upper Wolfcampian) Dolomite/limestone Council Grove Shallow shelf Success
pump (DHI) (Wolfcampian) carbonate
OK Modified plunger rod 100 70 NA NA Osage Fractured carbonate not stated Failure
pump (DHI)
Alberta Modified plunger rod 1,100 NA 800 60 -27 Success
pump (DHI)
Alberta Modified plunger rod 131 26 350 150 167 Unknown
pump (DHI)
Alberta Modified plunger rod 220 116 270 128 23 Unknown
pump (DHI)
Alberta Modified plunger rod 1,043 182 800 135 -23 Economic failure
pump (DHI)
KS Modified plunger rod 428 144 500 530 17 Failure
pump (DHI)
KS Modified plunger rod Shut in Shut in 148 250 Failure
pump (DHI)
KS Modified plunger rod 45 80 30 125 -33 Failure
pump (DHI)
KS Modified plunger rod 100 384 110 285 10 Success
pump (DHI)
LA Modified plunger rod 175 250 200 200 14 Failure
pump (DHI)
MI Modified plunger rod 50 350 9 289 -82 Economic failure
pump (DHI)
NE Modified plunger rod 150 300 120 365 -20 Success
pump (DHI)
OK Modified plunger rod 200 250 165 250 -18 Failure
pump (DHI)
TX Modified plunger rod 250 80 530 144 112 Failure
pump (DHI)
 Table 2 - DGWS Installation Data from GRI (1999) Page 3 of 3

Pre- GRI's
State/ DGWS Post- Post-DGWS Qualitative
Province/ Pre-DGWS Water DGWS Water % Increase Injection Measure of
Country Type of DGWS Gas (mcfd) (bpd) Gas (mcfd) Injected (bpd) in Gas Production Formation Lithology Formation Lithology Performance
TX Modified plunger rod 350 250 750 300 114 Success
pump (DHI)
OK Modified plunger rod 200 80 343 200 72 Probably Chase Failure
pump (DHI)
TX Modified plunger rod 250 300 100 300 -60 Probably Chase Success
pump (DHI)
KS Modified plunger rod 40 60 0 112 -100 Probably Council Grove Failure
pump (DHI)
OK Modified plunger rod 400 200 100 286 -75 Carmichael sand member of Topeka Sands Tonkawa sand Sands Failure
pump (DHI) Limestone Group member of
Douglas Group
OK Modified plunger rod 300 500 125 640 -58 Morrow Sandstone Failure
pump (DHI)
KS Modified plunger rod 352 50 200 100 -43 Not stated Sandstone Economic failure
pump (DHI)
OK Modified plunger rod 120 40 226 260 88 Upper Prue (aka Lagonda) Sandstone Lower Prue Sandstone Success
pump (DHI)
 Table 3 - Data on DGWS Installations Other Than GRI (1999) Page 1 of 2

Post- Post- Prod. and

Pre- Post- DGWS DGWS Injection Inj. Forma-
State/ Pre- DGWS DGWS Water Water to Pressure tion Trial Qualitative
Operator and Well Province DGWS Water Gas Injected Surface % Increase Casing Production Injection Differen- Separa- Starting Trial Ending Source of Measure of
Name Field Country Type of DGWS Gas (mcfd) (bpd) (mcfd) (bpd) (bpd) in Gas Size (in.) Formation Lithology Formation Lithology tial (psi) tion (ft) Date Date Comments Information Performance
Olympia et al. Bittern Alberta Bypass tool 565 440 777 195 38 Glauconitic Basal 222 403 Feb-96 Feb-96 Bypass pump Nichol and Good
10-24-046-22W4 sandstone quartz became unseated Marsh (1997)
sandstone after a few days

PanCanadian Countess Alberta Downhole water Shut in Shut in >1,000 315 0 Upper Bow Clastic Lower Bow Clastic Jan-01 Some initial injectivity Roche Good
Countess 100/5-27-17 injection tool Island sandstone Island sandstone problems (2001)
16 W4M (Chriscor and
Kudu)

Ferintosh 14-29 Ferintosh Alberta Downhole water 0 200 300 0 5.5 Ellerslie Sandstone Ellerslie Sandstone 400 82 Oct-02 Continuing Corrosion problems Powell Good
injection tool due to 5% CO2 in the (2004)
(Chriscor and gas
Kudu)

Ferintosh 06-32 Ferintosh Alberta Downhole water 0 250 75 0 4.5 Ellerslie Sandstone Ellerslie Sandstone 0 75 Mar-03 Continuing Corrosion problems Powell Good
injection tool due to 5% CO2 in the (2004)
(Chriscor and gas
Kudu)

RAAG Friedburg 5 Molasse Austria Subsurface side 3,500 880 3,500 880 90 0 7 Upper Stacked Lower Stacked 1,300 Apr-03 2003 Clemens and Good
Basin door (not Puchkirchen turbidite Puchkirchen turbidite Burgstaller
specified but Sands clastics Sands clastics (2004)
believed to be a
bypass tool)

OK Modified plunger Shut in Shut in 50 70 4.5 Shallow coal Coal Depleted 400 79 This may be the Phelps Good
rod pump (DHI) beds Mississippian same as one of the (2002)
oil zone coal seam trials
found in Table 2

OK Modified plunger Shut in Shut in 65 68 4.5 Shallow coal Coal Depleted 955 366 This may be the Phelps Good
rod pump (DHI) beds Mississippian same as one of the (2002)
oil zone coal seam trials
found in Table 2

Addison Energy 6-18- Windfall Alberta Downhole water 529 (peak) 75 0 Notikewan Pekisko Jul-00 2003 or later Saved $160K in Hill (2003) Good
59-14W5 injection tool water disposal costs,
(Chriscor) earned $545K from
additional recovered
gas as of 2003

Anadarko Milhon B3 KS Modified plunger 98 50 172 160 0 76 Nov-99 DHI Good

rod pump (DHI) (undated)

OKIE Crude Carbonex OK Modified plunger 49 2 128 128 0 161 The Dutcher, Deeper Mar-02 DHI Good
#1 rod pump (DHI) Spiro, Huntoon (undated)
Foster, Formation
Wapanueka
producing
zones in the
Huntoon
Formation

XTO Energy Teel 1-22 OK Modified plunger 225 39 258 43 0 15 Apr-01 DHI Good
rod pump (DHI) (undated)
 Table 3 - Data on DGWS Installations Other Than GRI (1999) Page 2 of 2

Post- Post- Prod. and

Pre- Post- DGWS DGWS Injection Inj. Forma-
State/ Pre- DGWS DGWS Water Water to Pressure tion Trial Qualitative
Operator and Well Province DGWS Water Gas Injected Surface % Increase Casing Production Injection Differen- Separa- Starting Trial Ending Source of Measure of
Name Field Country Type of DGWS Gas (mcfd) (bpd) (mcfd) (bpd) (bpd) in Gas Size (in.) Formation Lithology Formation Lithology tial (psi) tion (ft) Date Date Comments Information Performance
Amoco Canada 15-8- Alberta Electric Shut in Shut in 1100 315 0 4.5 Lower Jul-98 Oct-98 Payout in one month Chalifoux Good
77-8W4 submersible pump Clearwater and Young
(Petrospec coiled (1999)
tubing)

Amoco Canada 06-9- Alberta Electric Shut in Shut in 128 89 0 4.5 Aug-98 Nov-98 Low gas rate due to Chalifoux Neutral
77-8W4 submersible pump low position in and Young (uneconomic)
(Petrospec coiled reservoir, formation (1999)
tubing) damage, and
depletion
Amoco Canada 9-14- Alberta Electric Shut in Shut in 250 252 0 4.5 Aug-98 Nov-98 Low gas rate due to Chalifoux Neutral
77-9W4 submersible pump low position in and Young (uneconomic)
(Petrospec coiled reservoir, formation (1999)
tubing) damage, and
depletion
Table 4 — Examples of DGWS Installations Made by DHI

State Basin Name Type of Gas

Michigan Michigan Basin Tight/fractured shale/CBM
Ohio Appalachian Basin Tight/fractured shale/CBM
Indiana Illinois Basin Fractured shale/CBM
Illinois Illinois Basin Fractured shale/CBM
Oklahoma Cherokee Basin CBM
Anadarko Basin Tight
Texas Permian Basin Tight
Fort Worth Basin Fractured shale
East Texas/Arkla
Basin Tight
Gulf Coast Basin Tight/fractured shale
Kansas Anadarko Basin Tight
Tight/fractured shale/CBM
Nebraska Denver Basin (Niobrara)
Colorado Piceance Basin Tight/fractured shale
Utah Uinta Basin Fractured shale
Paradox Basin Fractured shale
New
Mexico San Juan Basin CBM

Source: DHI undated

Table 5 - Data on DOWS Performance and Qualitative Ranking* Page 1 of 2
Pre- Post-
Pre- Post- DOWS DOWS % Trial Trial Overall
DOWS Oil DOWS % Increase Water Water Decrease Water Starting Ending Longevity Performance
Lithology (bpd) Oil (bpd) in Oil Oil Rating* (bpd) (bpd) in Water Rating* Date Date Rating* Rating
Carbonate/ 19 24 26 Good 1,780 59 97 Good Jul-94 Jan-95 Good Good
carbonate
Sandstone/ 44 100 127 Good 380 95 75 Good Jul-95 Good
sandstone
Sandstone/ 25 100 300 Good 820 160 80 Good Aug-95 Good
sandstone
Sandstone/ 38 37 -3 Poor 1,200 220 82 Good Sep-95 Neutral
sandstone
Sandstone/ 3 10 233 Good 184 126 32 Good Oct-95 Good
sandstone
Sandstone/ 21 17 -19 Poor 690 Dec-95 Poor
sandstone
Sandstone/ 34 14 -59 Poor 979 Dec-95 Poor
sandstone
Sandstone/ 9.4 16 70 Good 546 Jan-96 Neutral
sandstone
Sandstone Feb-96 Poor

Carbonate/ 13 164 1162 Good 428 239 44 Good May-96 Good

carbonate
Carbonate/ 6 39 550 Good 629 21 97 Good May-96 Good
carbonate
Carbonate/ 16 33 106 Good 252 139 45 Good Jul-96 May-97 Good Good
carbonate
Carbonate/ 176 264 50 Good 3,648 264 93 Good Jul-96 Good
carbonate
Carbonate/ 113 277 145 Good 2,516 126 95 Good Aug-96 Good
carbonate
Carbonate/ 6 6 0 Neutral 655 150 77 Good Aug-96 Apr-97 Good Good
unknown
Sandstone/ 45 32 -29 Poor 1,400 500 64 Good Aug-96 Poor
sandstone
Sandstone/ 7 16.5 136 Good 269 127 53 Good Sep-96 Good
sandstone
Carbonate/ 20 15 -25 Poor 220 190 14 Neutral Jan-97 Poor
carbonate
Sandstone 25 32 28 Good 250 25 90 Good Feb-97 Good

Sandstone/ 5 10 100 Good 190 38 80 Good Feb-97 Mar-97 Neutral Good

sandstone
Carbonate/ 88 50 -43 Poor 1,700 189 89 Good Apr-97 Poor
sandstone
Carbonate/ 75 84 12 Neutral 517 14 97 Good May-97 Aug-97 Neutral Good
carbonate
Carbonate/ 27 26 -4 Poor 932 179 81 Good May-97 Neutral
carbonate
Sandstone/ 30 38 27 Good 470 61 87 Good May-97 Nov-97 Good Good
sandstone
Sandstone/ 631 14 -98 Poor 7,060 1,153 84 Good May-97 Jun-97 Neutral Poor
sandstone
Sandstone/ 76 0 -100 Poor 2,450 380 84 Good May-97 Nov-97 Good Poor
sandstone
Carbonate/ 70 78 11 Neutral 4,000 320 92 Good Jun-97 Good
carbonate
Sandstone/ 8 10 25 Good 451 63 86 Good Jun-97 Oct-97 Good Good
sandstone
Carbonate/ 21 117 457 Good 1,038 217 79 Good Jul-97 Good
carbonate
Carbonate/ 35 403 57 86 Good Jul-97 Neutral
carbonate
Carbonate/ 94 133 41 Good 1,560 586 62 Good Jul-97 Dec-97 Good Good
sandstone
Sandstone/ 15 26 73 Good 150 Jul-97 Neutral
sandstone
Table 5 - Data on DOWS Performance and Qualitative Ranking* Page 2 of 2
Pre- Post-
Pre- Post- DOWS DOWS % Trial Trial Overall
DOWS Oil DOWS % Increase Water Water Decrease Water Starting Ending Longevity Performance
Lithology (bpd) Oil (bpd) in Oil Oil Rating* (bpd) (bpd) in Water Rating* Date Date Rating* Rating
Carbonate/ 63 38 -40 Poor 1,260 63 95 Good Aug-97 Poor
carbonate
Carbonate/ 25 2 -92 Poor 315 54 83 Good Aug-97 Mar-98 Good Poor
carbonate
Sandstone/ 10 31 210 Good 470 168 64 Good Sep-97 Mar-00 Good Good
sandstone
Carbonate/ 35 35 0 Neutral 976 227 77 Good Oct-97 Mar-98 Good Good
carbonate
Carbonate/ 19 62 226 Good 352 250 29 Neutral Nov-97 Good
carbonate
Carbonate/ 24.5 16 -35 Poor 458 Jan-98 Mar-98 Neutral Poor
carbonate
Sandstone/ 53 80 51 Good 2,994 150 95 Good Apr-98 Good
sandstone
Sandstone/ 57 41 -28 Poor 2,463 567 77 Good Apr-98 Nov-98 Good Poor
sandstone
Carbonate/ Jul-98 Poor
carbonate
Sandstone/ 28 25 -11 Poor 1,387 352 75 Good Aug-98 Neutral
sandstone
Carbonate/ 86 47 -45 Poor 7,692 567 93 Good Sep-98 Jan-00 Good Poor
sandstone
Carbonate/ 19 31 63 Good 961 16 98 Good Oct-98 May-01 Good Good
sandstone
Sandstone/ 62 71 15 Neutral 3,402 167 95 Good Oct-98 Good
sandstone
Sandstone/ 560 560 0 Neutral 7,440 560 92 Good Oct-98 Good
sandstone
Sandstone/ 17 7 -59 Poor 173 70 60 Good Jan-99 Aug-99 Good Poor
sandstone
Sandstone/ 18 18 0 Neutral 1,052 265 75 Good Feb-99 Nov-00 Good Good
sandstone
Sandstone/ 51 51 0 Neutral 1,408 117 92 Good Jul-99 Oct-00 Good Good
sandstone
Sandstone/ 1,903 2,200 16 Neutral 6,747 1,800 73 Good Sep-00 Oct-00 Neutral Good
sandstone
Unknown 462 708 53 Good 3,840 954 75 Good Feb-01 Mar-01 Neutral Good

Unknown 636 275 -57 Poor 8,964 2,800 69 Good Apr-01 Apr-02 Neutral Poor

Unknown 118 118 0 Neutral 668 118 82 Good May-01 Dec-03 Good Good

Unknown 300 800 167 Good 8,000 3,700 54 Good Dec-01 May-02 Good Good

Unknown 57 57 0 Neutral 2,295 138 94 Good Jun-02 Dec-03 Good Good

Sandstone/ 38 38 0 Neutral 1,972 254 87 Good Oct-02 May-03 Good Good

sandstone
Carbonate/ 100 3,000 Poor
carbonate
Sandstone/ 13 18 38 Good 252 60 76 Good Good
sandstone
Sandstone/ 50 37 -26 Poor 441 69 84 Good Poor
sandstone

* Qualitative ratings are:

Rating Oil Water Longevity
Good >20% >30% >3 months
Neutral 0-20% 0-30% 0-3 months
Poor <0%
 Table 6 — Comparison of Performance and Geologic Conditions for 59 DOWS
Trials Contained in Table 1

Geology of Producing
Formation/Injection # Trials # Trials # Trials Total % Trials % Trials
Formation Rated Rated Rated # of Rated Rated
Good Neutral Poor Trials Good Poor
Carbonate/carbonate 11 2 6 19 58 32
Carbonate/sandstone 2 0 2 4 50 50
Carbonate/unknown 1 0 0 1 100 0
Sandstone/sandstone 16 4 8 28 57 28
Don’t know both, but 1 0 1 2 100 50
at least one is
sandstone
Unknown 4 0 1 5 80 20
Totals 35 6 18 59 59 31

Table 7 — Comparison of Performance and Geologic Conditions for 48 DGWS

Trials Contained in Table 2

% Trials
Geology of # Trials % Trials Rated
Producing # Trials # Trials Rated # Trials Total # Rated Failure or
Formation/ Rated Rated Economic Rated of Success Economic
Injection Success Failure Failure Unknown Trials Failure
Formation
Carbonate/ 7 3 0 0 10 70 30
carbonate
Carbonate/ 1 0 0 0 1 100 0
sandstone
Coal/ 1 2 0 0 3 33 67
sandstone
Sandstone/ 10 1 0 0 11 91 9
sandstone
Sandstone/ 0 1 2 0 3 0 100
unknown
Unknown/ 7 8 3 2 20 35 55
unknown
Totals 26 15 5 2 48 54 42