PETE 325 PETROLEUM PRODUCTION SYSTEMS LAB
Lab Week 13: Workovers and Subsurface Water Management
Objectives:
 Demonstrate knowledge of various workover approaches for a variety of problems.
 Utilize existing data to diagnose mechanism of excess water production.
 Recommend a water shutoff technology for a workover based on diagnosed
mechanism and current available technologies.
Equipment: You will definitely need at a minimum the Class slides and SPE 70067. You
may use other SPE papers and other technical resources (service company web sites, etc.)
as you wish. Just document any resources you use.
Your Report:
Descriptions of methods, tools and technologies:
Do parts 1 and 2 individually in the lab and turn in to your TA before leaving lab.
1. Describe in a few sentences how each of the following works, the types of wells
where they can be used, the general types of interventions that can be performed
and the relative costs (and why) of using
a. Bullead injection
b. Wireline (slickline and electric line)
c. Coiled tubing
d. Workover rig
2. Describe in a few sentences the following workover tools/technologies. Include
(i) what the tool/technology is generally used for, (ii) the definition and principle
of operation of the tool/technology, (iii) the types of wells generally used in
(vertical, horizontal) and (iv) how they are installed/introduced to the well or
reservoir
a. Sidetrack
b. Inflow control device
c. Swell packer
d. Casing patch
e. Well tractor
f. Cement squeeze
g. Rigid polymer gel
h. Flowing polymer gel
i. Bridge plug
i. Inflatable
ii. Wireline conveyed
Problem Diagnosis and Case Histories 1 and 2: Do as a team. Turn in report in one
week.
Problem Diagnosis:
You oversee a vertical well in a field with an average depth of 8500’ to midperforations, with a bottomhole temperature of 190° F. A combination of log and core
data led geologists to indicate that the absolute permeability of the 20-foot thick
producing interval is 50 - 75 mD, producing oil of 28° API at 2.0 cp viscosity at
bottom hole conditions. GOR is very low—you may assume black oil. The field is on
waterflood (maintaining original reservoir pressure of 3800 psi) with producers
draining on 80-acre spacing (assume circular drainage area). The 8” wellbore is
perforated across the 20-ft thick sandstone interval. Your well produced dry oil for
two years, followed by three years of increasing water cut, so that at the end of five
years the well was producing at 50% water cut. Because of the high water cut, the
well’s flow rate has decreased to the point where artificial lift is required—an ESP
designed to handle up to 700 barrels of fluid per day was installed just above the
perforations. After installation of the ESP water cut (brine S.G = 1.05; = 0.45 cp @
190° F) immediately jumped to 95%, with a total liquid production rate that maxed
out the pump. You ran a larger pump which led to a total fluid rate of 2600 barrels per
day with water cut of 95% or slightly higher and a bottom hole flowing pressure of
2000 psi with the well on ESP.
a. Determine (with explanation), using only the data given, a plausible
mechanism for the initial increase in water cut from zero to 50%.
b. Determine (with explanation), using only the data given, a plausible
mechanism for the jump in water cut from 50% to 95% upon installation
of the ESP.
c. What additional data, if any, might help you more clearly determine the
mechanism of water influx?
d. Explain, with justification, what you might do (or not do, if you think the
problem cannot be remedied) to decrease the water cut on this well.
Case Histories:
For the following cases write an Analysis with three sections that describes
(i)
how the problem is diagnosed (and additional information that would be
helpful for further tying down the diagnosis, if any),
(ii)
options for shutting off excess water (or gas) production and
(iii)
which option you would use and why.
You may use relevant SPE papers (these cases have been published); reference the
paper(s) and use your own words in your analysis. And you do not have to use the
same technology for solving the problem as is reported in the literature.
Case No 1.
The well at right is a producer completed in two intervals, one
above and one below a competent shale. The expanding gas cap
of this reservoir eventually caused coning into the upper
perforations and eventual depletion of liquid hydrocarbon from
that zone. The perforations were squeezed with cement, which
had an immediate positive effect on the GOR, as seen in the
figure below. However, shortly after the squeeze, the GOR
rapidly climbed back to pre-squeeze levels and higher (see
production history at top of next page), indicating that either gas
had found the lower set of perforations or the squeeze had failed.
A production log was run to identify the location of gas influx.
(see next page)
You are faced with choosing a technology for shutting off the
excess gas. If the gas influx is due to failure of the original
squeeze, you are reluctant to re-squeeze with cement, since previous experience has indicated
that success rate for a re-squeeze is at most 40%, which is unacceptable to your boss. The
temperature of the formation (190° F) is compatible with most modern technologies for
closing off perforations.
Logs below are lined up so that depths match
on each. Notes:
1. Spinner is proportional to flow rate
(increasing to right)
2. Normally, with liquid entering
wellbore from same depth as
perforations, temperature would do a
gradual, nearly linear decrease from
perforations to surface. (Temp
increases to right)
Case No. 2
The candidate is a waterflood producer drilled on the periphery of the field, where total pay thickness of
the ~50 – 100-mD sandstone is <50 ft and formation temperature is ~90°C (195°F). Reservoir pressure at
time of treatment was ~3,200 psi. The completion is a cased and cemented liner that is nearly horizontal
(85°) through the pay zone. The well was terminated at 11,853 ft measured depth (9,009 ft true vertical
depth). Lost circulation problems were encountered during drilling beginning at 11,327 ft; returns averaged
70% from there to total depth. Gamma ray/neutron logs showed washed out shale at 11,335 ft, with repeats
in the log that suggested faulting. A cement bond log indicated poor bond quality uphole from 11,338 ft.
The gas-lifted well was completed with 4.5-in. tubing from surface to 10,640 ft. The 7-in. liner was
perforated over the intervals 10,690 – 10,800 ft and 11,235 – 11,580 ft. It produced initially at 1,500 barrels
of oil per day at 24% water cut. However, within three months, the oil rate had dropped to ~400 BOPD at
~90% water cut. A production log indicated that all measurable production occurred between 11,327 and
11,345 ft. There was a +1°C (1.8°F) temperature anomaly at 11,338 ft, with no other anomalies noted. Thus
all significant inflow was from, or very near, the faulted interval. The well had produced over 3.7 million
barrels of water, which was shown by analysis to be nearly 100% aquifer water. All data supported a
mechanism whereby the near-horizontal portion of the wellbore intersected a fault in the vicinity of 11,338
ft that connected the wellbore to the underlying aquifer. The aquifer was estimated to lie ~50 ft below the
wellbore. Because of reserves at risk, options included sidetracking the well or attempting to shut off water
influx.
1.
2.
3.
In your report draw a diagram of this well and add all pertinent information from the write up
above.
List any additional information you believe would be helpful for making a decision on what to do
with this well.
Recommend, and state your reasoning, a feasible method for significantly decreasing the water
influx into this well (sidetracking the well is too expensive!)