Workover Strategies in CHOPS Wells
About the Authors:
Maurice Dusseault is deputy
director of the Porous Media Research Institute and a professor of
geological engineering in the Earth Sciences Department, University of
Waterloo. After flunking out of University in 1965, Maurice started in the
oil industry as a roughneck for a year, then as a drilling fluids
specialist for two years. He returned to university and eventually
obtained a Ph.D. in civil engineering in 1977 from the University of
Alberta on the subject of oil sand properties. He was also awarded a
five-year AOSTRA (Alberta Oil Sands Technology and Research Authority)
Professorship, held in civil and mineral engineering at the University of
Alberta until 1982, when he went to Waterloo to become chair of the
Geological Engineering Program. Maurice has been the chairman of the
Geological Engineering Program at the University of Waterloo several
times, and was also director of the Porous Media Research Institute from
1995 to 2000. He carries out research in petroleum geomechanics, new
production methods, and deep waste disposal. He has co-authored two
textbooks and over 350 professional articles in conferences and journals.
He works with industry as an advisor on many projects involving heavy oil
production, borehole stability, hydraulic fracturing, sand management, and
reservoir geomechanics, and is the instructor of a series of short courses
that he has developed.
Kirby Hayes, Kirby Hayes
Incorporated, has worked with several cased hole wireline companies, with
various responsibilities, primarily in the heavy oil region, since the
mid-1970s. He is currently a contract marketing representative for
numerous service and product providers to the petroleum industry. Kirby is
a member of the Lloydminster Petroleum Society (serving on its executive
for eight years), the Lloydminster OTS, and took an active role in the
planning and fundraising for the OTS Heavy Oil Science Centre. He has
conducted numerous workshops, courses and has authored and co-authored
several papers all of which relates to heavy oil production.
Michael Kremer graduated
from the University of Alberta with a B.Sc. in petroleum engineering in
1986. He is currently employed with Husky Energy Inc. in their heavy oil
group as the district production coordinator at Lloydminster, Alberta.
Mike has worked in most of areas involving heavy oil, and the CHOP process
from reservoir to wellhead, from battery to pipeline, and from refinery/upgrader
to finished products. This extensive knowledge of heavy oil has made
enabled Mike to become very adept at troubleshooting and solving heavy oil
related problems.
Chris Wallin has enjoyed
spending most of his career working in heavy oil. He spent six years in
Lloydminster working as a heavy oil production engineer with Petrovera and
Nexen, focusing on mainly CHOPS well. Chris has 3 years of heavy oil
exploitation experience and is employed with Enerplus in Calgary as a sr
development engineer, where he is concentrating on heavy oil waterfloods.
Chris graduated with a bachelor’s degree in chemical engineering from the
University of Saskatchewan in 1995. He is a registered professional
engineer in Alberta and Saskatchewan, and a member of the Petroleum
Society and the SPE. He was also an executive member on the Lloydminster
and District Heavy Oil Section of the Petroleum Society for 3 years.
Authors’ note: July 2004
After
reviewing this article and materials posted on the web we feel they still
have as much merit as when they were written and compiled (August, 2002).
When the workshop was conceived and conducted (March, 2000) we felt a need
for the industry to improve workover practices related to cold heavy oil
production. Although minor improvements have been attempted by a few
individuals, the need for major improvement still exists. Some of the
minor improvements are new technologies, tools, services, products and
some logical combined workover method programs (examples are chemical
placements and stimulation followed by clean out methods). A specific
improvement that came directly from this initiative is the concept to
follow up a particular workover strategy with a post workover production
strategy that is congruent with the workover strategy (an example is
Continuous pump to surface with a surge tool). For more current
information please fell free to contact one of the Authors.
The most
fruitful area for continued OPEX (Operating Expense) reductions in CHOPS
(Cold Heavy Oil Production with Sand) operations now appears to be well
workovers to solve mechanical and reservoir problems, and to improve
production rates. Workovers (exclusive of water blocking methods) were the
subject of a one-day workshop organized by the Lloydminster and District
Heavy Oil Section of the Petroleum Society in Lloydminster, March 15,
2000. Approximately 35 attendees participated in a wide-ranging discussion
of various workover methods. Participants discussed well problems
requiring workovers, and evaluated technologies for re-establishing
production under various conditions. Attendees represented companies and
agencies such as Petrovera, Husky, ExxonMobil, Anadarko, Nexen, the
Alberta Research Council, and the Universities of Waterloo (Ontario) and
Alberta (Edmonton).
The full
information package that was developed for the workshop may be accessed
from
http://www.lloydminsterheavyoil.com/completionscience.htm.
Development and assessment of workover techniques is a “work-in-progress”;
these charts and slides are designed only as a guide to technical advances
and to workover assessment. We feel strongly that the time has come
for a joint industry project on the economic assessment of various
workover approaches to optimize workover planning.
Introduction:
CHOPS (Cold Heavy Oil Production
with Sand) has been successfully implemented in many Canadian heavy oil
fields (Figure 1) ranging in viscosity from 1,000 to 55,000 cP. CHOPS
involves massive continuous sand influx, from 0.5%/vol to as high as 10%/vol
during the steady-state phase of oil production. This sand influx, and the
necessity to maintain it to sustain economical oil production, generates
an unusual set of operational demands, and operators are gradually
developing better production methods, waste disposal methods, and workover
methods. A typical CHOPS well produces 5 – 25 m3/day
(30 – 150 bbl/day) of oil, and, for a good well in viscous oil, perhaps as
much as 500 – 800 tonnes of sand in a year. Most CHOPS wells now use
progressing cavity pumps with surface drives, as these give good oil rates
while handing large sand volumes and eliminateing rod fall problems.
Workovers are required during the life of a well to change or repair
equipment, and to maintain or re-initiate sand and fluid influx.
The basic operational goal in the
petroleum industry is to produce maximum oil with minimum OPEX over an
optimal time to maximize netback. In the period between 1990 – 1998, the
heavy oil industry in the Lloydminster area reduced OPEX in CHOPS wells
from about $75/m3
to $44/m3
($12.00/bbl to $7.00/bbl). This was achieved in large part through
conversion to progressing cavity pumps, but also because of many
micro-engineering advances in handling and disposing of sand, in
developing better workover equipment and methods, and in refining details
of well design. Currently, over 100,000 m3/d
(600,000 bbl/d) of heavy oil are produced in Canada using CHOPS technology*,
comprising over 20% of total Canadian oil production. This production
level could easily be doubled in 24 months if the upgrading capacity in
North America were expanded accordingly. Production capability and OPEX
are no longer impediments to the development of Canadian heavy oil: the
bottleneck is limited upgrading capacity.
Types of Failure:
A selected list of references to
mechanisms, modelling and mechanics of CHOPS is provided on the website.
Oil production from CHOPS wells
generally increases for some time after the initial completion, then
declines over a period of many months, perhaps years. The rate of
production decline occasionally is sudden and unexpected: the root cause
may be mechanical, or it may be related to wellbore or reservoir
behaviour.
Mechanical failures (e.g.,
flowline plugging, stator failure) can usually be diagnosed easily;
however, the root cause may relate to reservoir phenomena. Sudden or
episodic sand slugs, episodic gas locking, concretionary nodules or metal
fragments destroying the stator elastomer, excessive water cuts leading to
sand settling, axial bucking of casing, and distortion of overburden
bedding planes causing casing shear may all lead to mechanical failures.
Bad diagnosis may lead to failure recurrence and production loss.
Reservoir “failures” are more
challenging to diagnose, because the location is usually inaccessible and
diagnostic data are incomplete, inaccurate, or contradictory. Root causes
include inability to initiate sand influx, near-wellbore or more distant
blockage of sand flow, loss of solution gas drive energy, and loss of
gravitational drive energy. Either gas or water coning may take place,
blockage of perforations may occur because of cement or concretion chunks,
flowing sand may recompact around the well and prevent oil ingress, and so
on.
CHOPS Reservoir Processes:
CHOPS requires sand flux; without
sand, oil rates drop to uneconomic levels. Conversely, encouraging sand
influx and dealing with it appropriately can result in substantial
increases in oil rates (Figure 2). This example shows four phases of
production in a CHOPS field in Saskatchewan (Luseland Field); the graph
basically depicts the production from the same wells over a period of 16
years. The first phase in the field involved low-rate production [average
less than 7 m3/d
(40 bbl/day) per well] using reciprocating pumps, with a very small amount
of sand influx. Phase II was an attempt to increase production through
horizontal wells, without success. Phase III was the period of
implementation of CHOPS through re-perforating with larger diameter ports,
changing to progressing cavity pumps, and learning how to operate the
wells with low annulus levels and continued sand flux of 3 – 5%. Phase IV
is the “steady” period of the field production under CHOPS. With the
increase in oil price in 2000, production increased to 20,000 m3/month
(4,200 bbl/day). At this time, the field continues to be highly productive
and profitable.
Sanding as a production
enhancement process requires continuous reservoir material destabilization
so that sand flux is maintained. Destabilization arises from gravitational
forces and pressure-driven forces, including foamy oil behaviour, where
bubbles come out of solution and expand while traveling toward the
wellbore. During the early production phase, sand cuts can be as high as
40 – 50% of the total produced dead fluids volume: this is a high-risk
period for wellbore blockage and pump failure, and workovers may be
needed.
If sand mobilization and flow are
impeded during the operation of the well, production will decline and even
cease. If flow velocities are low, sand may settle around the wellbore and
recompact. The well perforations may become plugged with arching sand
particles (particularly larger particles). In these cases, clays,
fine-grained minerals, and precipitated asphaltenes plug the pore throats
of the re-compacted sand around the well, virtually eliminating the
permeability. Production rates in a good well can drop from 16 – 32 m3/day
to 0.8 m3/day
(100 – 200 bbl/day to 5 bbl/day) over a period of a few weeks to a few
months.
If there is insufficient
gravitational and pressure destabilization in the far-field, the well
“disconnects” from the drive forces, and flow declines rapidly. Virgin
pressures can be encountered in the inter-well regions after many years of
production, so it appears that viscous oil in situ is a Bingham fluid,
requiring a discrete gradient to begin flowing. This explains the
“disconnect” behaviour, and leads to workover methods to “reconnect” wells
and re-establish the driving forces. As long as there is solution gas
under pressure and the overburden can move downward, sand flux toward the
wellbore will be maintained.
Massive water breakthrough is the
most difficult reservoir problem to rectify; water exclusion methods in
CHOPS wells have a long history of failures. At the present time, we are
not making any recommendations in the area of water flux to CHOPS wells.
Public information available is insufficient to evaluate this problem and
arrive at a “best recommended practice.”
Through research and the analysis
of field data, the physical processes involved in CHOPS are becoming
better understood. Our observation is that field operators who understand
the physics of the processes are more successful in well management and
production improvement. Thus, providing this knowledge to engineers and
operators (see articles in the bibliography) is a smart investment.
Time Series Information:
Water cuts may remain low for
years, and then gradually increase, or they may suddenly increase over a
few days to dominate fluid production. Early in CHOPS well production,
sand concentrations are generally high, but they fall to values of 1 – 8%
in a few weeks or months. Sand rates, as well as the speed with which the
initially high sand cuts drop with time, depend on oil viscosity, well
annulus drawdown, and well pumping strategy. Designing appropriate
workover methods in cases where sand and water rates suddenly change
requires collection and analysis of time-series history for a number of
well parameters.
We recommend that data be
maintained on each well for sand and fluids cuts (SOR, GOR, WOR), pumping
parameters, and annulus and pumping pressures. Downhole tubing-mounted
pressure gauges are recommended for BHP data. Gas collection is difficult;
nevertheless, changing GOR may be diagnostic in many cases. Anomalous
events should be registered and details of all irregularities, workovers,
or interventions should be documented in a consistent manner. The amount
of sand cleaned from the well during a workover should be recorded, and it
is useful to sieve produced sand or sand cleaned up during a workover
through a 5 mm screen to detect and identify large chunks of natural or
foreign matter, which may help identify the source of the problem.
How often should data be recorded?
Conservation authorities require monthly reporting of water and oil
production, but “events” can occur in a much shorter time frame. Gas
contents cannot be determined easily and quickly and no requirement for
sand cut reporting exists, yet these are vital time-series data. We
recommend GOR analysis once a month, and sand cuts once a week, using an
averaging technique over several days or hours to obtain a representative
value.
Automation is recommended whenever
possible. BHP gauges can give annulus pressures and tubing pressures above
the pump, as well as temperature. However, continuous recording of
gas-sand-oil-water production rates is not possible, as no reliable
four-phase metering system yet exists. We point out that even if such a
system is developed, operating under conditions of non-equilibrium in
highly viscous oil means that true determination of GOR in “real-time”
will remain extremely challenging, if not impossible. Methane dissolved in
heavy oil takes a long time to fully come out of solution, much longer
than the characteristic time of production; therefore it is probably
impossible ever to measure true GOR except through the use of bulk vacuum
bottle samples and laboratory analysis.
Types of
Workover:
Mechanical Root Cause Workovers
Surface or down-hole hardware
failure is the most obvious reason for a workover. If the problem is
down-hole, all equipment must be pulled from the wellbore. In some cases,
the purpose of intervention may be to upgrade pumping equipment,
reperforate the well, or access a new zone. These are windows of
opportunity to improve production (proactive workovers, rather than
reactive workovers).
Well Blockage Root Cause Workovers
Wells may fully or partially block
internally because of degradation of pumping efficacy (typically elastomer
failure), or because of a change in fluid composition. These wells must be
cleaned of sand, which may involve only fluid introduction into the
annulus, or may require a complete removal of tubular goods.
Pump-to-surface, foam clean-outs, or mechanical sand bailing are the major
approaches. It is impossible to displace in a conventional manner and
obtain fluid and sand returns to surface because, in all CHOPS reservoirs,
the fracture pressure is less than the hydrostatic pressure. This is due
to sand removal and concomitant loss of lateral stress.
Near-Field Root Cause Workovers
CHOPS wells may block externally,
near the wellbore. If perforations are partially impeded, sand, fines, and
asphaltenes will accumulate so that the perforation is completely
ineffective. Blockages may arise from chunks of cement, concretionary
nodules, shale fragments, or from the formation of stable sand arches
behind the ports. Aggressive introduction of fluids, rocket propellants,
re-perforations, and pressure pulse workovers appear to be effective
mitigation methods, and processes such as sand bailing and surging while
running in the hole may also help open ports.
In some cases, there is a complete
failure to initiate sanding when the well is first placed on production,
perhaps because the formation has some cohesion, perhaps because the
completion failed to damage and remold enough sand around the well to
trigger sand flow. Workover processes that massively perturb the strata
near the well (pulsing, rocket propellants, extremely aggressive swapping)
are used to overcome this.
Far-Field Root Cause Workovers
Far-field problems are more
difficult to diagnose, and require larger energy inputs because the
blockage is remote. Sand may be sedimenting and recompacting under low
fluid velocities. A “disconnect” from far-field energy sources may take
place because of Bingham fluid behaviour, low gradients, or the loss of
gravitational destabilization of sand from shearing and dilation. The loss
of gravitational drive implies that the interwell regions have stabilized
and can fully support the overburden. Destabilizing these regions or
overcoming remote Bingham-type problems requires an energy input that
travels out many tens of metres.
Solving far-field root causes
requires large energy inputs: large volumes of fluids can be introduced
aggressively, large or repeated rocket propellant treatment may be used,
or pressure pulsing can be employed. Reperforations, swabbing, fluid
loading, and sand bailing are considered too low energy to “shake-up” the
far-field strata enough to overcome these problems.
Workover
Methods:
We have chosen to present the
workover information in a number of tables available on the website; these
constitute the core of the article.
Workover methods may be classified
in various ways. Table 1 divides them into “quick-fixes,” cleanouts, and
methods to cope with absence of flow. Costs are usually low, moderate, and
high for the three groups, respectively.
In Table 2, our descriptive scheme
and ranking are presented. Perturbation level refers to the physical
energy level the reservoir experiences: bailing is slightly perturbing,
pressure pulsing massively so. The nature of the perturbation differs from
slow, mild and repetitive surges (wireline bailers) to a single sudden
high velocity impact (rocket propellant).
Relative expense has also been
listed on the classification charts. This is difficult to estimate in a
study such as this; the best approach is to solicit service cost estimates
from an independent company and to study previous data carefully.
A “workover of opportunity” or
combining several approaches can increase chances of success and may
reduce costs. Combining a well cleanout with a fluid injection workover is
common. During pressure pulsing, reservoir compatible fluids may be added,
and toward the end of the workover, a treatment chemical may be
introduced. Other examples include perforation washing while foaming,
perforating while foaming, and chemical treatments while perforation
washing, perforating, or propellant stimulation.
Tables 3, 4, and 5 are examples of
the three classes of workovers listed in Table 1. Our choice is random,
and in no way implies that they are better or worse than the other 10 – 15
approaches. It is worth repeating that different approaches are suitable
for different root causes; therefore a method that is highly effective in
unblocking perforations, for example, may be ineffective in
re-establishing linkage with extant far-field pressures.
Staged Workover
Strategy
Workover costs range from perhaps
$1,000 for an annulus loading with a single pump truck load (3 to 10 m3
of fluid) to $30,000 for a full pump change-out combined with a pressure
pulse workover, a task requiring several days of service rig time.
The range of costs and causes lead
naturally to the concept of a staged approach to manage risk. The “steps”
in this approach are:
• Carefully analyse the
situation to identify the root cause;
• Rank order options in terms of
chances of well improvement;
• Rank order workover methods in
terms of cost;
• Complete a cost-benefit
estimate to arrive at a final ranking;
• Stage the workover attempts to
reflect the final ranking chosen;
• Execute the workovers under
the supervision of experienced personnel who record all the pertinent
data;
• Perform the cheapest workover
approach first. In general, avoid pulling the equipment out of the hole,
as this requires a service rig, and rig time is often the major cost
factor in a workover;
• Be prepared to be flexible and
change strategy “on-the-fly” as more data become available during the
workover execution phases;
• Follow up with a careful
economics-based analysis to evaluate the workover success;
• Don’t just archive the data;
add it to the corporate knowledge base and disseminate this information to
other operators and engineers in the company.
For a detailed flow chart of this approach refer to steps in problem
solving at
http://www.lloydminsterheavyoil.com/workoverview.pdf
It is possible to delineate diagnostic procedures, and place them into a
solid scientific and engineering framework. This will help in choosing
optimum strategies, but there are no magic formulae; each company must
collect the necessary monitoring information, implement a diagnostic
framework, choose optimal workover strategies, and assess the economic
success in individual assets. Inadequate data collection or reluctance to
establish a diagnostic framework leads to lost opportunity and lost
profits. Diagnosis relies on a sound understanding of the physical
processes taking place in the reservoir, just as optimizing workover
practices requires data collection and analysis.
Cost-benefit analyses of all
workovers should be executed systematically, using production time series
information as a comparative database. The Canadian heavy oil industry
definition of an economic success for a workover is one that pays for its
costs plus OPEX in the 90 day period after the well is returned to
production. This sounds short, but remember that CHOPS wells may need
repeated workovers, the price for heavy oil is often depressed, and
individual wells are (at best) moderate producers: 25 m3/d
(150 bbl/day) is an excellent heavy oil well.
Summary
No set of instructions can be
developed from this study; optimizing workover strategies is a work in
progress that must be undertaken by each company. There are different
options, different opinions, different cases and different costs;
therefore, a rational risk-and-return-based approach must be used. What
form and type of problem solving approach is best depends on each
company’s operating philosophy. There is no “magic pill” or “cookie cutter
approach” that will work in every situation or in all assets. A thorough,
methodical approach will result in choosing the best tool, and using it
properly. There is also room for an industry-wide joint study to assess
the efficacy of the various techniques in various circumstances. We
recommend that this be undertaken.
Acknowledgements
D. Pavka, Anadarko; J. Bootsman, Petrovera; and
C. Gall, Private Consultant, assisted greatly with the development of the
tables and the format of the workshop. Many engineers and operators in the
Lloydminster area have discussed these issues with us, and the March 15,
2000 workshop generated many helpful comments.
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Also the flush-by table that appears both in the tables for the article
and the power point slides has an error. The rating of 1 (seldom) should
be changed to 3 (often).
