SPE 40044
Waterflooding Heterogeneous Reservoirs: An Overview of Industry Experiences and
Practices
Karl E. Gulick, SPE and William D. McCain, Jr., SPE, S. A. Holditch & Associates, Inc.
Copyright 1998, Society of Petroleum Engineers, Inc.
This paper was prepared for presentation at the 1998 SPE International Petroleum Conference
and Exhibition of Mexico held in Villahermosa, Mexico, 3-5 March 1998.
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Abstract
This paper reviews waterflood management practices,
highlighting key industry papers. It is intended to move
readers up the “learning curve” and provide a road map for
implementing and operating a successful waterflood project. It
will assist reservoir engineers, production-operations
engineers, and development geologists who are involved in or
are contemplating waterflood operations.
The paper addresses operating philosophy, well spacing
(density), pattern development (selection), completions,
injection water, and surveillance. Although these factors are
presented from a west Texas perspective, they are applicable
to reservoirs having a high degree of vertical and areal
heterogeneity.
In addition to a brief history of waterflooding, the paper
reflects “lessons learned” through years of experience in
waterflooding and CO2 flooding carbonate reservoirs,
principally in west Texas. This experience has been gained
through work in both a major and a large independent oil
company, through interfacing with outside operators of all
sizes, and through consulting for small, independent oil
companies.
Introduction
Many of the world’s oil reservoirs produce by a solution gas
drive mechanism. This drive mechanism has inherently low
reservoir energy, which usually leaves a large portion of the
original oil in place in the reservoir when the wells reach their
economic limit. In addition, many of these oil reservoirs are
heterogeneous. That is, these fields are not thick, clean, sand
sections with strong water drives.
One of the cheapest and most popular methods of restoring
and maintaining reservoir energy is to inject water into the
reservoir; i.e., waterflooding. Although this process has been
around for over 50 years, the fundamentals are buried in
numerous papers and books.
This paper presents the
essentials of waterflooding that the authors have discovered
throughout their careers, supported by excerpts from the
literature.
A Brief History of Waterflooding
Although the history of waterflooding dates back as early as
1865, the use of waterflooding as a recovery method did not
come into widespread acceptance and use until the early
1950’s.1 In west Texas, there was a significant expansion of
the oil industry in the 1950’s with the discovery of a number
of very large fields such as Wasson, Slaughter, Levelland,
North and South Cowden, Means, and Seminole. Statewide
rules forced most fields to be developed on a density of 40
acres per producing well. These solution gas drive reservoirs
were found in highly heterogeneous shallow shelf
carbonates.2-5 Consequently, reservoir energy depleted within
a few short years and producing rates dropped rapidly. To
compound matters, many of the wells were completed in only
the high permeability streaks and well above any possible
water production.
Water injection was implemented to restore oil production
rates. The typical waterflood development scenario went
something like this: First, some wells around the perimeter of
the property were converted to water injection, thus creating a
“peripheral waterflood.” An alternative scheme was a single
line of injectors through the center of the field.6,7 When this
had only minimal effect, largely due to low injectivity in the
relatively low permeability reservoirs (0.1 to 20 md.), some
interior wells were converted to water injection. Often the
wells converted were the poorer producing wells or were
selected so as to set up an inverted 9-spot pattern (3 producing
wells for every injection well). In the 1970’s, it was realized
that the conversion of wells to water injection effectively
raised the density of producing wells to a value greater than 40
acres per producing well. Drilling additional producing wells
2
K. E. GULICK AND W. D. McCAIN, JR.
and converting more wells to injection, so as to return to a
well density of 40 acres per producing well, usually created an
infill drilled pattern waterflood with one producing well for
every injection well. This yielded a total well density of 20
acres per well. In addition to accelerating production, the
higher well density increased ultimate recovery. As time
progressed, watercuts increased and wells were worked over.
Lower permeability pay could be opened and completion
intervals extended closer to the oil-water contact, thus
improving production but not increasing the watercut.5
Basic Waterflooding Philosophy
Waterflooding is largely common sense. If one sets out a plan
and executes it, the project’s success is significantly improved.
The key tenets of a successful waterflooding plan are:
• Start the waterflood early in the field’s life.
• Understand the reservoir’s geology.
• Infill drill to reduce lateral pay discontinuities.
• Develop the field with a pattern waterflood that has
one injection well per producing well (i.e., 5-spot or
line drive).
• Have all of the pay open in both injection wells and
producing wells.
• Keep all producing wells pumped off.
• Inject below formation parting pressure.
• Inject clean water.
• Operate the waterflood based on injection well tests.
• Conduct a surveillance program.
The remainder of this paper examines each of these tenets
and integrates them into a unified philosophy.
Early Waterflood Start-up
When primary depletion occurs, the reservoir pressure drops
to the oil’s saturation pressure (bubble point), and then gas
starts coming out of solution in the reservoir. With additional
depletion, gas saturation is created in the reservoir. When
waterflooding is started, this gas saturation must be collapsed
before waterflood response can occur. The delay in waterflood
response hurts the economics of the project. In addition, the
loss of solution gas from the crude oil increases the viscosity
of the oil, thereby lowering the flow rate of oil. The increase
in viscosity also adversely affects the mobility ratio, which in
turn decreases the areal sweep efficiency.
If the reservoir reaches an advanced state of depletion prior
to the start of water injection, the project may be doomed to
failure. A plot of producing gas-oil ratio (GOR) versus
cumulative oil production for a solution gas drive reservoir
will start out at a constant value until the bubble point is
reached, will increase to a maximum value, and then will
rapidly decrease.8 If a field’s GOR is in this last stage, the
reservoir may be too depleted to be successfully waterflooded.
These two points suggest that an early start to
waterflooding will speed up the recovery process and thereby
improve the economic performance of the field. Start-up of
SPE 40044
waterflood operations early in a field’s life, even in very large
offshore fields, has been successful in the past.9
Understanding the Field’s Geology
It is hard to develop or redevelop a field in the optimum
manner if the field’s geology is not well understood. It is
critical for reservoir studies that as much data as possible be
collected for each well. For starters, a good suite of openhole
logs, including gamma ray, neutron porosity, density porosity,
acoustic porosity (for synthetic seismic to tie back to 2-D and
3-D seismic data and for stress profiles to design
stimulations), deep resistivity, and Rxo logs are a must. It has
also been proven that a 200 MHz di-electric log can be very
beneficial in determining the oil-water contact. Some people
are tempted to forego openhole logging of infill wells. This is
a big mistake! Reservoirs can change dramatically between
wells, especially in shallow shelf carbonates. Every round of
drilling has brought changes in the geological description of a
reservoir.
Besides logs, a good areal distribution of whole cores that
cut the entire section are necessary to define the permeability
distributions throughout the field. Observation of a core that
is fresh out of the core barrel, especially in a 30-year-old
waterflood, can give the engineer (and even the geologist)
great insights into what makes that field tick. If the reservoir
is believed to be fractured, an oriented core can reveal the
orientation of those fractures. This knowledge will greatly
help in orientation of the waterflood patterns.
Almost as important to a newly discovered field as
openhole logs, are a bottomhole sample of the produced fluids
and a bottomhole pressure measurement. These are often
overlooked in the excitement of a new discovery, but almost
every reservoir engineer has lamented not having (and
probably cursed his/her predecessor for not obtaining) these
data. The costs of obtaining and analyzing a fluid sample and
getting a pressure measurement are insignificant with respect
to the cost of field development.
If a carefully controlled pressure drawdown test,
immediately followed by a pressure buildup test, is conducted
early in the producing life of the field, such reservoir
characteristics as permeability-thickness, drainage radius,
distance to reservoir boundaries, and determination of whether
the reservoir is a dual porosity system can be ascertained.
Factors critical to such testing are 1) proper design of the test,
especially if it is a layered reservoir, 2) conduct the test before
a free gas saturation is established, and 3) test as many wells
as possible.10
Many companies have created multi-disciplinary teams,
including geologists, geophysicists, petrophysicists, reservoir
engineers, production engineers, and facilities engineers,
whose job is to study older waterflood projects in an attempt
to improve recovery. Such teams have generally worked
well.5,6,11,12
This appears to be due to increased
communications and awareness of the level of detail required
for building reservoir descriptions to be used in full field
reservoir simulations. In general, stratified reservoirs must be
SPE 40044
WATERFLOODING HETEROGENEOUS RESERVOIRS: AN OVERVIEW OF INDUSTRY EXPERIENCES AND PRACTICES
mapped on a much finer vertical resolution than customary for
most geologists. For example, a reservoir that would normally
be mapped as two or three zones may require subdivision into
eight or ten zones and the aquifer layers may have to be
quantified. Typically this is done by correlating and mapping
the major vertical barriers to flow, then mapping the pay in
between. In addition, research shows that capillary pressure
forces in oil-wet carbonates can create barriers to the vertical
flow of water.13
Well Density
In heterogeneous reservoirs, changes in facies trap oil or
shield the oil from the sweeping action of injection water.
Driscoll14 discussed the concept of lateral pay discontinuities.
Reducing the inter-well distance through infill drilling reduces
these lateral pay discontinuities, thus improving areal and
vertical sweep efficiencies and increasing recovery. Time and
again this concept has proven true.14-18 In west Texas, almost
every San Andres and Clearfork field has been infill drilled to
at least 20 acres per well and some have been reduced to 10
and even 5 acres per well, always with an increase in ultimate
recovery. (If there were no increase in reservoir continuity, the
producing rate would increase but the ultimate recovery would
remain the same.)
After an extensive study of a number of closely spaced 4in. diameter whole cores from the Reeves (San Andres) field
in Yoakum County, TX, Danielli2 concluded that the flow
units in this shallow shelf dolomite could not be tracked from
one well to the next if the well density was more than about 10
acres per well (660 ft between wells). Her conclusions about
the areal and vertical heterogeneity of these type reservoirs
lend strong geological support as to why infill drilling
increases recovery.
Prudhoe Bay benefited from infill drilling and waterflood
pattern size reduction.18 It has even been reported that a thick
(950 ft of oil column) relatively clean sandstone of high
porosity (22%) and relatively high permeability (640 md) had
an increase in ultimate recovery from infill drilling.19
Besides the issue of lateral pay discontinuities is the issue
of the time it will take to sweep the reservoir volume.
Obviously, higher well density means more oil recovered in a
shorter time.
Starting a waterflood at one well density and then
downspacing to a higher well density can have adverse
consequences. The relative permeability effects of water from
the original injection patterns may lead to water cycling on
one side of a pattern while the other side is in the prime of its
waterflood response. Therefore, infill drilling prior to starting
a waterflood is advisable. Economic evaluation of several
well density scenarios should determine the optimum well
density.
Increased environmental concerns about injection wellbore
integrity (i.e., corroded casing that may not have cement
behind the pipe), the cost of laying new production flowlines
in addition to injection lines, and the cost of moving pumping
3
units and their electrical service support drilling new injection
wells instead of converting old producers, whenever possible.
Waterflood Pattern Selection
As stated earlier, heterogeneous reservoirs, especially those of
fairly low permeability, have not responded well to nonpattern waterflooding.
The low injectivity of these
heterogeneous formations will not allow injection to keep up
with current withdrawals, let alone to fill up and repressurize
the reservoir from previous production. Even fields with
injection schemes that had interior injection such as a line of
injectors for every three lines of producers has failed to
effectively waterflood the field.6,20 Eventually, most
waterfloods have ended up on some form of repeating
waterflood pattern.
Patterns that have a producer-to-injector ratio of one have
been the most popular. The equal distances between injection
wells and producing wells and the ability to provide sufficient
injection have led to the success of 5-spot and line drive
patterns. Inverted 9-spot patterns, with their three-to-one
producer to injector ratio and half of the wells spaced only
70% as far away from the injector as the other wells, have not
proven to work as well in heterogeneous carbonate reservoirs.
Orientation of waterflood patterns can be critical if there is
a preferential permeability direction, natural fracturing, or a
combination of in-situ stresses and rock properties that would
cause the formation to fracture in a particular direction during
stimulation or injection above parting pressure. In old
waterfloods, production data may give insights into this.
Otherwise, acoustic anisotropy tests on oriented whole core
samples may be the only source of insight into how one should
orient the waterflood patterns.
Well Completions
All wells, both production wells and injection wells, must be
completed in all of the hydrocarbon productive rock. In many
old fields, the wells were perforated only in the highest
porosity streaks (which presumably had the highest
permeability). Often, these completions were planned without
comparing them to offset wells. When waterflooding was
started, no attention was paid to which zones were open.
Years later, when integrated study teams built cross sections
through all of the wells, completion interval inconsistencies
from well to well became apparent.11 Well recompletion and
infill drilling projects have confirmed the existence of
bypassed oil.5
Compounding the inconsistencies in completion intervals
is the notion that water injected into these stratified reservoirs
will spread out vertically and contact more of reservoir than
was originally perforated. This is not always the case. Thin
shale streaks and dense/tight streaks, which are often too thin
to significantly affect log response (and are therefore not
identifiable on logs), can act as horizontal baffles in the
reservoir and thereby impede vertical flow.
Once injection has been established in a wellbore, it may
be difficult to effectively open and stimulate new intervals,
4
K. E. GULICK AND W. D. McCAIN, JR.
due mostly to relative permeability effects (i.e., the aqueous
stimulation fluids tend to enter the high water saturation zones
caused by the water injection and, therefore, not enter and
stimulate the newly opened zones).
Another factor in early initial completions was the desire
to make water-free completions. However, waterfloods
produce water. Therefore, why not open up a zone that will
make oil at a 50% watercut when the field is at an even higher
watercut? There is a large volume of oil between the point of
water-free oil production and 100% water production. The
only caution is in having injection wells completed too close
to water. The potential for lost injection into the aquifer is
significant.
The moral of the story is that successful
waterflooding of the entire pay is contingent on having all of
the pay open and stimulated.
Producing Well Operations
Most if not all producing wells in waterfloods should be on
artificial lift.21 Other than the ratio of drainage radius to
effective wellbore radius (which can be altered by reducing
well spacing and wellbore stimulation), the only term in
Darcy’s Law that we can improve is the pressure inside the
wellbore (Pwell flowing), which is accomplished through the use
of artificial lift. Keeping wells pumped off will make Pwell
flowing nearly zero, and therefore, production will be
maximized. If a well is not pumped off, not only will
production decrease with lower pressure zones ceasing to
produce (killing sweep efficiency), but crossflow can occur,
which hurts production even more.21 If the crossflow is from a
high watercut zone into a low watercut zone, relative
permeability damage can occur.
The selection and proper sizing of artificial lift equipment
has been greatly simplified through the development of a
number of computer programs. But more important is the
development of well management systems that optimize the
operation of wells. Pump-off controllers do not allow
pumping units to operate when the wells have insufficient
fluid left to pump, which wastes energy and contributes to
sucker rod failures. The more sophisticated designs also
provide diagnostic information for the engineer. Solar/battery
operated remote transmission units (RTU’s) can be hooked up
to pumping units to alert field personnel of pumping system
failures. The automation of oilfields with computerized
supervisory-control and data-acquisition systems has been
shown to significantly improve the profitability of oilfield
operations.22
Injection Well Operations
On the injection well side, flow and pressure measurement
equipment can be tied into computer monitoring systems
many miles away by the use of solar/battery operated remote
transmission units (RTU’s). This permits accurate tracking of
injection volumes and surface injection pressures.
The main objective of operating an individual injection
well is to inject the maximum amount of water without having
SPE 40044
it go out of the intended pay zone. The first part requires that
water be injected at the highest pressure possible. The second
part limits the injection pressure to just below formation
parting pressure. In practice, operators commonly use a
surface injection pressure of 50 psig below formation parting
pressure minus the static pressure of a column of injection
fluid.
Injection Water Quality
Injecting water that is laden with oil and/or suspended solids
equals one thing: a plugged up injection wellbore that is
incapable of taking the maximum amount of water. Therefore,
clean injection water is imperative.
There are four main problems with injection water: 1)
dissolved solids in the injection water that can precipitate and
form scale, 2) oil and suspended solids that can plug
wellbores, 3) oxygen in the water that can cause corrosion,
and 4) bacteria in the system that can cause corrosion and
suspended solids. Patton has written a book23 that is an
excellent treatise on all aspects of water associated with the
production of petroleum. He has summarized many of these
issues in his SPE Distinguished Author Series paper.24
Cleanup of injection water can be accomplished either by
filtration or by providing sufficient settling time for solids and
oil breakout. Research by Amoco Production Company25 that
shows that standard tanks, with or without internal baffles,
provide only a fraction of the theoretical retention time due to
the water channeling directly from the tank inlet to the tank
outlet. They have designed and patented a vortex settling tank
system that significantly improves this retention time
efficiency. Cleanup of injection water and remediation of the
clogged wellbores provided significant improvement in west
Texas and in Alaskan North Slope.26, 27
Many operators worry about the chemical compatibility of
injected water with formation water. They fear that the
formation will become plugged if scale precipitates in the
formation. Patton23 dispels this concern by pointing out that
there is very little contact between injection water and
formation water in the reservoir.
However, the problem of scale precipitation in the
producing wellbore persists. In carbonate systems, especially
where anhydrite or gypsum is present, the injected water will
dissolve minerals as it moves through the formation until it
reaches saturation, and then it will precipitate scale as pressure
drops in the wellbore. The only effective solution to this
problem is to squeeze scale inhibitor into the formation
periodically, but these treatments can be expensive.
To avoid both scale problems and the high cost of
inhibitors, many operators use fresh water for their make-up
water. But we have seen that there isn’t a problem in the
formation, and fresh water doesn’t necessarily solve the
problem in the wellbore. Brackish water used as make-up
water with a split injection system can be a better alternative
to the use of fresh water which is needed for human
consumption and irrigation.
SPE 40044
WATERFLOODING HETEROGENEOUS RESERVOIRS: AN OVERVIEW OF INDUSTRY EXPERIENCES AND PRACTICES
The injection system itself is a third location of concern for
scale formation. Tanks, injection pumps, and injection lines
are subject to scaling if make-up water and produced water
have scaling tendencies and are mixed prior to injection.
Splitting the injection system is the best solution for
preventing scale precipitation in surface injection facilities.
Having a tank and pump system for both make-up water and
produced water avoids mixing the incompatible waters. The
changing volumes of produced and make-up water can be
balanced by using an injection flowline manifold constructed
so that either produced or make-up water can be selected for
each well.
Waterflood Operations Using Injection Well Testing
Because waterflooding is recovery of oil by means of
water injection, it follows that management of the waterflood
project should have management of the injection wells as its
primary focus. Kelm and Robertson28 proposed a waterflood
management scheme using periodic injection well testing as
the main management tool. They contend that by running step
rate tests to determine the current formation parting pressure,
temperature surveys and radioactive tracer surveys to
determine injection profiles, and pressure falloff tests to
determine skin factor, fracture half length, and reservoir
pressure, the injection --and therefore waterflood performance
--could be optimized.
One of the toughest and often most ignored facets of
waterflooding is injection conformance. The question is, is
the injection water going where it should (vertical distribution)
in the injection well? Measurement of injection conformance
can be done with radioactive tracer surveys,28, 29 temperature
surveys,28 and production logging (spinner surveys).30
Injection conformance has also been measured using oxygen
activation logging.31, 32 Three dimensional reservoir simulation
that incorporates the data from injection profiles can greatly
aid in understanding a waterflood’s performance.30
While measuring a well’s injection profile is an established
practice, rectifying an injection well’s conformance is another
matter. The use of cement, micro-particles, foams, polymers,
selective completions, and multiple packer completions have
all been used with varying success.33-35 The success or failure
of the profile modification workover is often dependent on the
mechanical condition of the wellbore and its effects on
properly placing the diverter. Corrosive injection water,
especially if it contains H2S, will destroy the injection well’s
casing below the packer. Some operators are installing
corrosion resistant casing (duplex stainless steel, fiberglass,
etc.) across injection well completion intervals to combat this
problem.
Waterflood Surveillance
The successful management of any waterflood project,
especially in stratified/heterogeneous reservoirs, relies heavily
on knowing what is going on in every well in the field; i.e.,
surveillance. Every waterflooded project has its own unique
situation. However, development of surveillance programs are
5
well documented.33, 34, 35 There are two very good SPE
Distinguished Author Series papers that outline the basic
considerations necessary for successful design of a
surveillance program, one by Thakur36 and the other by
Talash.37
The key ingredient of any surveillance program is accurate
data collection. The accuracy and frequency of the data
collected limit a waterflood management system.9 Time and
time again, we have conducted reservoir studies using data
that were sparse, inaccurate, or non-existent.
The most basic data are production volumes. Monthly
testing of each producing well is essential, preferably for a
minimum of 24 hours using a three-phase separator. Many
operators just take occasional tests using a two-phase
separator, measuring only the total liquid production,
estimating the oil and water percentages from a sample or
sightglass, and not measuring the gas production -- all at
pressure conditions that can be significantly different from
those at the tank battery. These tests must then be used to
allocate the total field back to each well. It is obvious that this
leads to a very inaccurate picture of gas-oil ratio performance,
locations of water breakthrough, injection-withdrawal ratios
for an injection pattern, and most importantly, sources of oil
production.
Almost as important is collection of water injection
volumes and surface injection pressures. Valuable insights
into the performance of the waterflood can be gained from
individual well plots of injection rate versus time, injection
pressure versus time, Hall Plots (cumulative wellhead pressure
* time vs. cumulative injection)38,
pattern injectionwithdrawal ratio plots, and total property injection-withdrawal
ratio plots.
The advent of high-speed personal computers with large
memory capacities has greatly facilitated automating
waterflood project surveillance. All manners of production
and injection data can be imported into spreadsheets or a
relational database.39 There are systems available by which the
field personnel input production measurements (such as raw
tank fluid levels) into an electronic notepad, return to the
office, plug the notepad into a computer, press a button, and
the data is automatically uploaded, the necessary calculations
performed, and the results transferred into the company's
production data and accounting systems. This eliminates
hours of hand calculations, the time lag of routing paper from
office to office, multiple people hand inputting data, and the
multiple opportunities for errors. Once the historical data is
imported, updated plots and reports can be easily generated
with each monthly update of the production and injection data.
This way, large volumes of data can be processed, put into
useable formats, and reviewed in a very short time with very
little effort.
The downside of being able to process data quickly is that
the results are only as good as the input data. For example,
injection water volumes measured by orifice meters, where the
orifice plate has been eroded from a perfectly square-edged
circular hole to a rounded-edged hole of indescribable shape
and unknown area, are totally worthless.
In short,
6
K. E. GULICK AND W. D. McCAIN, JR.
measurement equipment must be maintained and used
properly, and measurements must be taken at proper
frequencies.
High powered PC’s and workstations and commercially
available 3-D finite difference reservoir simulation software
have provided even the smallest independent operator with
another powerful reservoir management tool: full-field
reservoir simulation.
Full-field simulations can locate
bypassed oil, identify viable (and uneconomic) drilling
locations, simulate changes in operations, and simulate
changes in waterflood pattern alignment.
The time, effort, and expense of developing a reservoir
model are easily justified by the money saved if foreseeable
development mistakes are avoided, or if operations can be
improved through reservoir simulation. Qualified petroleum
engineering consultants can perform reservoir simulation
studies cost effectively, if an operator does not have the inhouse expertise to build the reservoir model.
Conclusions
Successful implementation and operation of a waterflood
project, even in complex heterogeneous formations, is a matter
of executing a well-conceived comprehensive plan, none of
the elements of which are “rocket science.”
Acknowledgments
The industry’s body of knowledge of waterflooding extends
well beyond that which has been reported in the literature.
The ideas, successes and failures of countless engineers,
geologists and field personnel have all combined to progress
waterflooding technology to its current state of maturity.
The efforts of Mrs. Ann Callaway in helping with the
literature search made this paper possible.
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2.
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SPE 40044
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