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In-depth Sweep Efficiency Improvement: Screening Criteria and Engineering
Approach for Pattern Evaluation and Potential Field Implementation (Russian)
Article · October 2012
DOI: 10.2118/160749-RU
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SPE 160749
In-depth Sweep Efficiency Improvement: Screening Criteria and Engineering
Approach for Pattern Evaluation and Potential Field Implementation
Manrique, E., Garmeh, G., Izadi, M., Salehi, M., Romero, J., Aye, N., Thomas, C., Shevelev, P. TIORCO, LLC
Copyright 2012, Society of Petroleum Engineers
This paper was prepared for presentation at the SPE Russian Oil & Gas Exploration & Production Technical Conference and Exhibition held in Moscow, Russia, 16–18 October 2012.
This paper was selected for presentation by an SPE program committee following review of information contained in an abstract submitted by the author(s). Contents of the paper have not been
reviewed by the Society of Petroleum Engineers and are subject to correction by the author(s). The material does not necessarily reflect any position of the Society of Petroleum Engineers, its
officers, or members. Electronic reproduction, dis tribution, or storage of any part of this paper without the written consent of the Society of Petroleum Engineers is prohibited. Permission to
reproduce in print is restricted to an abstract of not more than 300 words; illustrations may not be copied. The abstract must contain conspicuous acknowledgment of SPE copyright.
Abstract
A common problem of waterflooded oil reservoirs is the premature water breakthrough bypassing high remaining oil
saturation in unswept zones that are risky targets for infill and sidetrack drilling. Early water breakthrough can be caused by
reservoir heterogeneity and unfavorable mobility ratios of oil and injected water. There are several IOR/EOR technologies tha t
can be used to reduce water production and increase sweep efficiency. Polymer gels (“Conformance treatments”), polymer
flooding and Colloidal Dispersion Gels (CDG) are some of the technologies most commonly used during the last few decades.
However, the applicability of a given technology will depend on the problem (e.g., water channeling, adverse mobility, etc.)
and its applicability under given reservoir conditions (e.g., temperature, salinity, lithology, and injection and fracturing
pressures, among others).
The purpose of this paper is to describe screening criteria for thermally-activated polymer (TAP) flooding technology
implementation before starting detailed project evaluations. Based on the suggested screening criteria and evaluation approach,
it is possible to rank patterns or asset candidates for in-depth conformance treatments to improve sweep efficiency or delay
premature water breakthrough. This is especially important for projects in remote areas or in offshore conditions where water
handling is costly.
Based on field experiences, laboratory experiments, and new simulation approaches that are being continually improved, indepth conformance treatments are carefully designed before pilot or asset implementation.
The proposed screening methodology was used to evaluate and rank temperature-triggered polymer applicability in more than
20 Russian oil fields. Results show how to identify good or poor candidates to evaluate the technology, which increases the
probability for successful implementation. In some other instances the combination of technologies might be required to
maximize ultimate recoveries.
Introduction
Identification, prediction and understanding of conformance problems are vital in optimal design of improved and enhanced
oil-recovery (IOR and EOR) process. Correct application of conformance improvement techniques can potentially lead to
greatly improved oil-recovery (IOR) from conventional oil reservoirs.
The term, conformance, is defined as the measure of the volumetric sweep efficiency during an oil -recovery flood or the
application of technology to reduce or eliminate excessive water production.
By means of the Mobility Ratio or a permeability profile from core samples, log data, and PLT/ILT it is possible to make an
initial estimate of potential conformance problems due to viscous-fingering or permeability heterogeneity.
Conformance problems often greatly reduce the rate of oil recovery from a given oil reservoir, as compared to a similar oil
reservoir that does not suffer from conformance problems. It is important to mention that about one-third of the OOIP is
mobile oil that is not recovered by conventional primary and secondary oil -recovery techniques because of reservoir
conformance problems in average on a worldwide basis.
Oilfield operators who apply conformance-improvement IOR and EOR operations in a reservoir where they have applied
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conventional primary and secondary operations , have an inherent advantage because they have a better understanding of the
geological and other reservoir characteristics, which could help increase the probability of success (lower risk/uncertainties)
during the application of any additional oil-recovery operation. The knowledge gained through primary and secondary
recovery operations in a reservoir includes a better understanding of geological structure, remaining reserves distribution, and
knowledge of production issues, can be more attractive economically for IOR/EOR methods employment for oil production
increase in comparison with attempting to grow production by means of new discoveries with associated unknown problems.
For economic reasons, when considering the recovery of the remaining oil (an average >60% of the OOIP) in mature
reservoirs, it is, in general, often more advantageous to apply conformance improvement EOR first because the
implementation of conformance improvement EOR operations is usually less expensive than the implementation of Residualsaturation oil-recovery (RSOR) techniques. Furthermore, the cost of the EOR application can prove to be quite expensive if
EOR flooding operations are conducted in the presence of substantial conformance problems because of the resultant need to
recycle the relatively costly EOR fluids through the reservoir.
Conformance-improvement techniques and operations performed in the near-wellbore region are, in general, less expensive,
easier, and less risky to apply compared to conformance-improvement treatments performed in the far-wellbore region.
Implementation of new technologies is an intense process in Russian oil fields. Currently, technologies such as hydraulic
fracturing, sidetrack, or infill drilling are the most widespread for oil recovery improvement in mature oil fields. However, in
well-developed waterfloods these technologies become more risky and decrease the potential and economic feasibility with
time or flood maturity. However, in mature waterfloods IOR/EOR technologies play a key role in improving oil recoveries and
reducing high operational cost and energy consumption for water disposal.
Regarding Russian experience in IOR/EOR technologies, most techniques that are used in Russian oil fields have been
developed by local corporate industry and academic research centers that include more than 400 technologies for conformance
with about 100 widely used (Sorkin et al., 2012). However, the use of Thermally- Activated Polymer (TAP) such as
®
BrightWater has been used in Russia to a lesser extent. TAP technology has been used to improve sweep efficiency in
waterflood projects in onshore and offshore fields. Despite the growing number of treatments and ongoing evaluations (e.g.,
Alaska, Argentina, Azerbaijan, Tunisia, West Africa, and West Siberia), few papers have been published documenting
selection criteria or field performance of recent treatments. Basic screening methods of TAP have been documented in the
literature (Cheung et al., 2007; Frampton et al., 2009; Pritchett et al, 2003; Garmeh et al., 2012). However, few papers have
been focused on more detailed screening and ranking criteria when evaluating a large number of well patterns for the
applicability of BrightWater® (TAP). Galli et al. (2012) and Mustoni et al. (2012) recently published detailed methodologies
to evaluate, rank and select candidates for BrightWater® applications in Tunisia and Argentina, respectively. These papers
provide a detailed evaluation approach from well selection and field implementation to project evaluation, monitoring and
economics. Similar methodologies have been implemented to evaluate and rank candidates for BrightWater® in several fields
in Russian oil fields. However, an important number of field tests implemented over the last three years have not been
documented in the literature. Therefore, the present paper is focused on summarizing recent laboratory, numerical simulation
and evaluation strategies developed for the proper design and implementation of TAP technology based on lessons learnt from
past and ongoing studies. Recommended strategies to define baseline conditions and monitoring strategies post TAP
treatments will be also addressed.
Common Reservoir and Development Process Description
Waterfloods are inefficient due to poor sweep efficiency contributed to by an adverse mobility ratio and heterogeneous
formations. Usually, reservoir engineers are well aware of the efficiency of their waterfloods. When the localized recovery
factor in a given reservoir sector is predicted to be high (60% of OOIP or better), and the amount of water required to achieve
this is 1.5 times the pattern pore volume or less, then there will be no significant target for oil production improvement
treatments.
Generally, the worse the waterflood performs, the more likely it is that an economic remedial treatment can be applied, but
there are exceptions. Examples include, poor sweep due to excessive reservoir compartmentalization or lack of reservoir
continuity, and highly fractured reservoirs.
In the early 1990’s it was recognized that the most difficult cases involved injection water “thief zones” that were in contact
with lower permeability zones of high remaining oil saturation. In such cases near well-bore treatments were ineffective and an
in-depth block appeared to be required to redistribute the pressures in the reservoir and mobilize the remaining oil (Frampton
et al. 2009). Since that time a consortium of companies (BP, Chevron, and Nalco) developed the new technology of TAP
conformance treatments, conducted laboratory studies, and field trials, and have pushed it into common practice for the oil
industry.
Development processes for most oil fields include injection of water for reservoir pressure maintenance and sweep efficiency
improvement. This process includes some additional disadvantages such as adverse mobility ratio when water viscosity is
SPE Number
3
much less than the viscosity of crude oil and causes severe viscous fingering and cools the reservoir when several pore
volumes of water have been pumped through the porous media. These factors must be taken into account during TAP
treatment design.
Screening Criteria for TAP Implementation
Screening criteria for TAP design and implementation are divided in two major steps; basic or decision making criteria and
extended or ranking criteria. Basic screening criteria, which is given below are examined to evaluate field potential for TAP
application:
a.
b.
c.
d.
e.
f.
g.
h.
Early water breakthrough to high water-cut. Considered field should suffer from early water breakthrough to a
substantial change in water-oil ratio. This represents a primary identification to infer the presence of a high flow
capacity channel or thief zone in the reservoir. Injection/production data should confirm that the injection water
predominately goes into pay zone and produced water is predominately the injected water due to water channeling.
The availability of injection profile (e.g. spinner surveys) and/or PLT can also contribute to confirm possible water
channeling (See monitoring section)
High permeability contrast is desirable. Generally, the higher the permeability contrasts the higher the probability of
having bypassed oil within the pay zone. The average permeability in the thief zone should be at least three times
higher than other low pay zones
Reservoir temperature should be between 20oC and 120oC. Current grades of TAP work at a given temperature
range and/or transit time. TAP activation times can also be adjusted with treatment concentrations as will be
described later in the paper
TAP works only in sandstone reservoirs. Carbonate reservoirs have low pH, which prevent TAP activation and they
can have a destructive cation-anion reaction that results in very high adsorption. Additionally, Carbonates
formations can be heavily fractured (e.g., vuggy carbonates) limiting TAP applicability
Injection water should have a pH greater than six. Lower pH shrinks the TAP particle size and reduces its
effectiveness (viscosification and adsorption characteristics of TAP)
Expected tracer transit time should be greater than 30 days. Generally, treatment strategy is to place the TAP half
way between injector and producer. However, this strategy will depend on several factors including thief zone
permeability
Injection water salinity should be under 150,000 ppm. Reported field experiences include formation brines up to
260,000 ppm (Ghaddab et al., 2010; Galli et al., 2012)
Minimal natural fracture existence
Based on recent TAP treatments a set of extended screening criteria has been proposed. Extended screening criteria can
contribute to ranking candidate patterns for TAP applications. Proposed extended criteria as follow:
a.
b.
c.
d.
e.
f.
Amount of moveable oil in the pattern. Higher moveable oil in the pattern will result in higher incremental oil after
TAP treatment. Patterns with fastest water breakthrough (compared to average reservoir performance) can lead to
largest incremental oil
Number of fracture jobs performed in the pattern (injector and producers). Better response is seen in patterns that
have lower number of fracture jobs. Generally, oil production wells with several frac jobs are converted to injectors
that may lead to shorter transit times difficult to estimate without tracer data. Therefore, the lower the number of frac
jobs in a given well pattern (Injectors and/or producers) the better unless transit times are higher than 30 days, which
require tracer data to determine.
Temperature gradient. Reservoirs that have greater temperature gradient between injection and reservoir temperature
would show better results. Narrow differences between water injection and reservoir temperatures makes treatment
design challenging. However, variables such as well spacing, thief zone permeability and injection rates, among
others, can overcome these operational conditions
Net pay thickness. Thicker pays (> 10m) with high permeability contrast show higher probability of unswept zones. If
net reservoir pay is too thick (> 30m) the review of net pay continuity and thief zone location in the stratigraphic
column (supported with log data and injection/production logs) is recommended to estimate possible dilution effects
and also evaluate the possibility of selective injection when necessary. This possible constraint may also apply for
reservoirs with commingled injection (i.e., simultaneous water injection in different reservoirs without selective
completions)
Reservoir heterogeneity (vertical communications). A Dykstra-Parson coefficient (DP) greater than 0.8 is desirable.
Well configuration and completions. Injection wells with the capability to run injection profiles (e.g., PLT) or set
packers for possible selective injection (if necessary) are suitable for TAP treatments. Wells with selective injection
(Páez Yañez et al., 2007; Mustoni et al., 2012) can reduce possible TAP treatment dilutions in multilayered systems.
Well architecture and completions with the flexibility for TAP monitoring are always preferred, especially to
demonstrate and evaluate the technology before larger applications are implemented
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g.
h.
Water cut in the pattern. The probability of larger unswept zone is higher in the case of lower water cut. High water
cuts (> 90%) will not limit the applicability of TAP (Ghaddab et al., 2010; Galli et al., 2012). However, if water cuts
are high in a mature waterflood, TAP treatment response may take longer depending on well interference with offset
injectors that can also cause dilution of the treatment. In these situations, TAP treatments in multiple wells represent a
viable strategy. On the other hand, if a particular pattern shows early water breakthrough, TAP treatment can be
considered at early stages of water injection increasing the potential for incremental recoveries
Injection and Production profiles. Thief zone injection profile of higher than 50% is desirable. Perforated intervals
with high intakes represent good candidates for TAP treatments. Incorporation of this information in numerical
models is key to better represent water channeling not always captured in 3D geo-modeling. This will be briefly
described later in the paper
Engineering Approach for Pattern Evaluation and Treatment Design
In this section the engineering approach to evaluate a pattern for TAP application and its steps is described. The evaluation is
started with the basic or decision-making criteria. After a reservoir/pattern passes the basic screening criteria the reservoir and
well data assessment in conjunction with extended screening criteria is performed.
First step after basic screening criteria is to evaluate injection and production historical data and well events. The analysis of
injection/production data helps to identify the target well(s), presence of a preferential channel between injectors and
producers, and type of problem that exists to identify the most adequate technology to be applied. When evaluating large areas,
the use of some basic reservoir and production information, such as maps of cumulative oil and water, water injection, water
oil ratio (WOR), and recovery factors (Fig. 1) can help to identify the areas with greatest problems in a fast and effectively
way without having to analyze each particular injection pattern.
Figure 1: An example of cumulative oil, water and WOR map to identify the area that has conformance problem.
Apart from the production and injection data analysis, it is necessary to review the recovery factors (primary and secondary),
connectivity between injectors and producers, reservoir heterogeneity (permeability variation), and mobility ratio among other
basic parameters that will help to select the best candidate. After selecting the area, identification of the problem and
completion of the analysis, the next step is to estimate the channel volume of the thief zone, which will be used as a starting
point for the preliminary treatment design.
Channel volume can be estimated using different methods and techniques; however, in this document, we will discuss only
two different approaches: 1) injection-production data analysis. In this method we first estimate the swept channel mobile
pore volume (MPV) between the injector and its offset producers. The MPV of the swept interval is estimated by creating a
WOR vs. cumulative oil (Np) plot per well and then calculating the cumulative secondary oil recovered at the offset producers
between the time water injection started and the time when water broke through at these wells (sudden increase in WOR). The
channel volume will be the volume of secondary oil displaced (swept) by water injection until water broke through. Channel
volume estimated with Np vs. WOR, can be adjusted using an allocation factor if more than one injector is affecting the
producers; 2) Transit volume from numerical simulations. If available, results from tracer injection programs can be also used
to estimate channel volumes. Channel volume estimation can be refined using injection (e.g., spinner surveys) or production
logging tools (PLT). These logs will also contribute to treatment design based on thief zone location within the
injection/production interval. The normal and rule-of-thumb treatment slug size is 5% of the channel volume though it may
vary from 1.25% to 10% of the channel volume. However, in case of injection time constraints (e.g., offshore applications)
generally treatment slug sizes are reduced and TAP concentration is increased depending on thief zone permeability and/or
crude oil viscosity. As of today concentrations of TAP field treatments have ranged from 3,000 to 15,000 ppm.
SPE Number
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Injection and production logging tools (ILT’s and PLT’s) as shown in Fig. 2 are useful tools to identify thief zone lateral
communication, injection profiles and location of the thief zone in the pay zone. In addition it contributes to estimation of
possible vertical dilutions that may be considered during treatment design.
Figure 2: An example of injection and production profile from PLT’s. It is a useful tool to identify thief zone lateral communication and
location in the pay zone.
Laboratory and Simulation studies
Laboratory and simulation studies are a part of the engineering approach for pattern evaluation. Laboratory studies include
water analysis, viscosity build up bottle tests, adsorption tests, and slimtube/core flood tests. A detailed experimental stu dy can
be found in Salehi et al. (2012).
TAP viscosity and static adsorption (bottle tests) data at reservoir temperature are the minimum laboratory tests required to
estimate project design and incremental recovery potential through numerical simulations. TAP viscosity at different
temperature (between injection and reservoir temperature) and static adsorption tests using different concentrations are always
recommended. Viscosity measurements vs. time (e.g., activation temperature and maximum viscosity reached) at different
shear rates are also required. For thick intervals and possible changes in mineralogy composition within the production
column, static adsorption tests using rock samples from different pay zones intervals might be required, especially for
reservoirs showing more than one thief zone and if bulk injection is planned.
Slimtube tests (1 ft- to 40-ft long) or corefloods, or both, can be conducted to evaluate TAP performance in porous media
(resistance and residual resistance factor) and obtain dyn amic adsorption values. Slimtubes could be packed by either cleaned
quartz sand or crushed reservoir material, or both and they can also be used to estimate thermal stability vs. time at reserv oir
temperature.
Fig. 3 shows some of the parameters that impact TAP viscosity. As it can be observed Fig. 3.a shows viscosity build up for
different TAP grades at the same condition. Fig. 3.b shows the impact of temperature on viscosity build up. It can be seen that
at higher temperature viscosity build up is faster. Fig. 3.c shows the impact of solution concentration on viscosity.
Fig. 4.a shows the impact of product grade on viscosity build up. Fig. 4b shows that at similar conditions, slower grade (e.g.
EC9378A) can generate similar viscosity build up as faster grades (e.g., EC9398A) by increasing its concentration. This
strategy can be used to consider the same TAP grade in a similar field with patterns showing different transit times.
Numerical simulation starts with history matching oil, water and gas production rates, and breakthrough times. It then
develops with injection profile match from PLT’s, history match of tracer tests (if available) to quantify channel volume, and
transit time. Fig. 5 shows an example of the importance of transit time, transit volume match in the model to accurately
capture field and thief zone performance. Next temperature gradient is estimated and based on the temperature gradient and
transit time, an appropriate grade of TAP is selected. A detailed simulation approach can be found i n Garmeh et al. (2011).
Fig. 6 shows an example of temperature profile at the end of history (before TAP treatment). As can be observed all the
patterns do not have similar temperature profiles depending on the thief zone flow capacity and transit time. Th erefore the
TAP activation region should be different in different patterns. In a similar scenario, an appropriate TAP concentration is
recommended to accurately place the TAP.
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(a)
(b)
(c)
Figure 3: a) Impact of TAP grade on viscosity build up at fixed concentration, water salinity, temperature and pH. b) Impact of
temperature on viscosity buildup of a TAP grade. c) Effect of TAP concentration on viscosity buildup.
(a)
(b)
Figure 4: a) Effect of TAP grade on viscosity build up at 10,000 ppm concentration. b) At similar conditions, slower grades (e.g.
EC9378A) can generate similar viscosity buildup as faster grades (e.g. EC9398A) by increasing its concentration. This strategy can be
used to consider the same TAP grade in a similar field with patterns showing different transit times.
SPE Number
Figure 5: An example of the importance of transit time and transit
volume match on history matching the field and thief zone
performance.
7
Figure 6: Temperature profile in the thief zone in a field.
Different thief zone flow capacity, transit time and amount of
the injected water are the reasons of different temperature
profile at each injector.
To model a thermally active polymer treatment, thermal and chemical modules of compositional simulations are combined.
Thermal simulation is used to capture temperature-triggered characteristics of the polymer. Therefore, injection and reservoir
temperatures, rock and fluids heat conductivities, and rock heat capacity are required information for thermal simulation. The
reservoir temperature profile is used to determine the grade that should be used in each specific treatment and it also helps to
target the placement at an optimum location in the thief zone. Next, a tracer test simulation is performed to determine the
transit time to the target location in the thief zone. Tracer transit volume is also used to confirm the thief zone channel volume
estimated from injection/production data.
Currently two simulation approaches are used to design TAP treatment.
Mechanistic approach:
In this approach no reaction is involved and fresh TAP is injected as a single chemical component at the injector and it has low
viscosity and low adsorption at the injection stage. TAP viscosity and adsorption is increased by temperature profile further
away from injector that has higher temperature. The time characteristic of the TAP is accounted for by travel distance in the
thief zone through transit time of the thief zone. Full activation region is defined based on the transit time of the thief zone and
popping time of the TAP grade from laboratory viscosity bottle test. Further details can be found in Garmeh et al. (2011),
Izgec & Shook (2011), and Salehi et al. (2012).
Kinetic reaction approach:
In this approach a temperature dependent kinetic reaction is used that accounts for time and temperature dependent viscosity of
TAP and its interaction (adsorption/retention) with reservoir rock. The reaction parameters are tuned by laboratory bottle test
(Fig. 7) and TAP activation is controlled by time and grid block temperature. Near the injector normally temperature is low
and TAP has slower rate of activation, which decreases the chance of popping around the injection well. The advantage of the
new approach is the continuous activation of the material by time and temperature over the instantaneous activation triggered
by temperature in the mechanistic approach.
After TAP grade selection based on laboratory tests and temperature profile estimation, series of sensitivity analyses are
performed to design TAP treatment for field implementation. Sensitivity analyses include TAP concentration, treatment
volume, adsorption/retention, resistance and residual resistance factors (RF/RRF), and injection/production rates. A sensitivity
analysis on TAP grades (fast vs. slow activation) is also performed to identify the optimal case. At the end the field result is
compared against numerical TAP design to identify the key tuning parameters.
8
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Figure 7: An example of bottle test viscosity match that is used
to tune temperature dependent reaction parameters.
Figure 8: An example of injection well head pressure monitoring
after TAP treatment that clearly shows the material’s activation
(Ghaddab et al., 2010; Galli et al., 2012)
Data Evaluation and Monitoring Strategies
To develop the proper treatment design and interpretation of TAP technology the definition of an adequate baseline and
monitoring program for the proper project evaluation is necessary. The present section will highlight key data gathering plans
and performance indicators used in multiple BrightWater® projects.
Data Evaluation and Base Line Definition
Recommended information to properly design and establish the base line before a TAP (e.g. BrightWater®) treatment
includes:
•
•
•
•
•
•
•
Define range of possible water injection temperatures (Key to define BrightWater grade, its concentration, and its
properties at injection conditions). Water injection temperature may change during seasons and/or operational
conditions characteristics of each field
Run temperature log at injector(s) candidate(s) for injection of TAP if not readily available. It is recommended to
have a recent injection temperature log, especially if perforated intervals changed (Important input data for simulation
to estimate temperature gradient for BrightWater grade selection and define laboratory plan for bottle and static
adsorption tests)
Historical injection/production data analysis to define well communication, channel volume estimation, and base
decline curve to be used for project evaluation and estimate incremental recovery and reserves
o Injection and production rates
o Total liquids, Water cuts, Water-Oil Ratios (WOR) and Gas-Oil-Ratios (GOR)
o Well events at offset producer(s) such as changes in lift rates (e.g., Gas lift, RPM in ESP’s) to understand its
effects on production response as part of the base line definition and for consideration in case changes in well
operating conditions post TAP treatment are implemented
Historical injection pressures (This will be used to monitor changes post treatment injection pressures)
o Evaluate historical changes in injection pressures vs. injection rates (Fig. 8)
o Evaluate Hall Plot previous BrightWater treatment
Run injection profile (e.g., PLT, spinner survey) to understand thief zone location and fluid intake within the pay
zone at different injection rates. This step is important to define base line, define injection strategy depending on thief
zone location, and adjust numerical models, among others
o Injection profiles at different injection rates are valuable to evaluate optimum injection rate to minimize (as much
as possible) dilution of the treatment slug.
o This step might not be necessary for injection wells with selective completions (e.g., multiple valves or sliding
sleeve completions)
Run Fall-Off Test (FOT). This test is important to define base line and compare with post treatment to estimate/infer
key TAP mechanisms to be described later in this section
Water compositional analysis of produced waters (This analysis will make it possible to accurately run qualitative and
quantitative test for presence of polymer and to detection possible interferences)
SPE Number
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If injection water composition is highly different from formation brine this information can be used as natural
tracers depending on waterflood maturity, water cuts, etc. (not always possible to use it as a natural tracer)
Tracer injection, if it is not readily available (Important to well communication and transit times supporting
BrightWater grade selection and its concentration). Tracer data are always desirable as part of TAP treatment designs
and numerical simulation studies. However, lack of tracer data will not limit the probability of success of TAP
treatments if possible uncertainties are managed properly. On the other hand, tracer data obtained before TAP
injection will provide the opportunity to repeat tracer injection after the treatment, which makes it possible to estimate
possible changes in transit times and contacted pore volume
o
•
Although data described above represents most common information evaluated to design TAP treatments (including lab and
simulation studies described in previous section), the more data incorporated to evaluate pattern(s) candidate(s) for TAP
technology the better. For example, in some recent field cases the following tests were also used before BrightWater®
treatments starts:
•
•
Step-Rate Test to estimate formation parting pressure if not readily available (Can contribute with TAP grade
selection and its concentration, monitoring purposes and/or define injection strategies based on injection pressure
capacity and permeability contrast between thief zone and low permeable zones). Some examples include:
o Injection pressures (rates) above frac gradient may induce TAP injection in intervals not required for in-depth
conformance improvement, which may cause dilution effects impacting treatment efficiency
o Injection pressures (rates) below frac gradient will favor TAP to flow in high capacity (thief zones). This
information can be integrated with the interpretation of injection profiles at different rates (e.g., PLT data). At
low injection rates it will be possible that over-pressured low permeable intervals produce water also impacting
treatment design
o For fields where the difference between injection capacities is close to reservoir pressure will give a reduced
margin for operating conditions that is important to understand for a proper grade selection, its concentration, and
consider it as part of treatment design and monitoring as well.
If PLT data are available in offset producer(s) in the pattern(s) of interest it will be also contribute to infer thief zone
lateral communication. However, authors understand the risk of well production interventions and deferred oil
production that can impact project economics. This test is not critical for TAP treatment design but is valuable for
reservoir characterization (e.g., thief zone lateral connectivity and validation of geologic/numerical model) and
potential monitoring
Monitoring Strategies
Basically, data gathered during and after TAP (e.g. BrightWater®) treatments as part of monitoring program is continuously
compared with the information used to develop treatment design and establish the base line. If no major changes are
implemented in operating conditions (pre and post treatment), TAP treatment evaluation and its interpretation can consider the
following steps:
•
•
Injection / production data analysis results critical to estimate incremental recovery and reserves using different
decline curve analysis approach
o Injection and production rates
§ Injection rates are expected to be kept constant during the evaluation of the project. However, this will
depend on injection pressure response due to TAP effects (in depth permeability reduction) and/or water
diversion into low permeable zones (TAP technology is not supposed to modify injection profile to a great
extent, even if it does occur)
§ Injection rates can be decreased in case of injection pressure close to frac gradient (e.g., water diversion in
low permeability zones combined with a reduced margin of reservoir pressure and injection pressure
capacity)
§ Injection rates can be increased to validate in-depth conformance effects after it is confirmed TAP has been
fully activated (adsorbed / retained). This can be inferred with Fall-Off Tests (FOT) and injection pressure
trends
o Total liquids, Water cuts, Water-Oil Ratios (WOR) and Gas-Oil-Ratios (GOR)
o Other operational conditions expected to be constant or with reasonably small changes (within a reasonable
margins) includes choke valve diameter, volume of gas used for gas lift, and RPM in ESP’s, among others
Injection pressures are key to evaluation of TAP performance and will vary depending on slug size and concentration
at injection (see Fig. 8):
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For TAP injections at viscosities lower than 2 cp, injection pressures are not expected to increase rapidly (This
information is provided during lab studies as part of project design at water injection temperature). Some
exemption includes:
§ Injection of fast TAP grades (depending on slug size injection as well)
§ Early TAP activation (e.g., fast grade, reservoir temperature reached earlier than expected, high water
injection temperature)
§ Low permeability reservoir with low permeability contrast between thief zone and unswept intervals
§ Combination of all the above
o For TAP injections at viscosities higher than 2 cp, injection pressures are expected to increase steadily to very
rapidly depending on TAP grade and its concentration. This pressure response can be seen when injecting slow
grades and high concentrations (usually 7,000 – 15,000 ppm range). Trends in pressure increase are provided as
part of treatment design using numerical simulation studies. Possible injection pressure response under these
conditions could be:
§ Steady increase of injection pressure until slug size is fully injected (Generally, when injecting high TAP
concentrations slug sizes tend to be smaller in high permeability thief zones)
§ When TAP slug injection has been completed injection pressure will slightly decrease when water injection
resumes displacing away TAP viscous slug
• Under this treatment condition a FOT is recommended a few days after the high concentration TAP
slug is injected (See Fall-Off Test below)
§ Injection pressure should start to increase steadily as TAP is starting to get activated (viscosity build up Resistance Factor effect - RF) and finally adsorbed / retained (Residual Resistance Factor effects - RRF)
Update Hall Plot after TAP treatment and track changes that may indicate increase in sweep improvement (Skin
effect increase)
Run injection profile (e.g., PLT, spinner survey) to confirm no changes in injection profile was caused by TAP
injection. Timing and frequency of injection profile logs will depend on treatment design (TAP grade and its
concentration), operational flexibility and/or budget constraints, among others. Some scenarios may include:
o Generally only one test is recommended to confirm no changes in injection profiles. This test can be run at least
3 months after TAP injection to be sure it has moved far away from the injector and has a comparable condition
to what existed before TAP was injected
§ This test can also consider different injection rates to be compared with the base line profile repeating as
much as possible operating conditions
o An additional option can consider the following scenarios:
§ Run an injection profile a few days after TAP slug was injected and run a second one at least 3 months after
TAP injection. This is in case operator is interested in validating the technology at pilot scale and
implementing detailed monitoring programs to generate a better understanding before a larger deployment
§ Consider different injection rates for the second injection profile using similar conditions used during the
establishment of the base line (Pre TAP treatment)
o If treated injection well has a selective completion (e.g., multiple valves or sliding sleeves completions),
monitoring plan will depend on the strategy post treatment if other zones will be re-opened after a given time of
the treatment. In some instances injection profiles might not be required or be possible to run due to completion
constraints
Run as many FOT as possible to evaluate different stages of TAP slug transitions and mechanisms. Timing and
frequency of FOTs will depend on TAP grade and its concentration at the injection. Number of tests to run and
interpret will be limited to budget availability for monitoring purposes. FOT program can consider the following
options:
o For slow TAP grades injected at low concentration (< 7,000 ppm that usually has viscosities below 2 cp as
injected) FOT can be run once injection pressure increase is noticeable suggesting TAP activation and/or
permeability boundary caused by TAP adsorption / retention
§ TAP viscosity as injected can vary from field to field. Therefore, the FOT program will depend on field
conditions and operator needs
o For TAP treatments using fast grades (at any concentration) or slow grades at high concentration (> 7,000 ppm
that usually has viscosities higher than 2 cp as injected) FOT program can consider the following protocol:
§ Run FOT a few days (3 to 7 days) after BrightWater slug is injected. At this stage a noticeable change in the
FOT parameters might be required due to high viscosity slug surrounding well bore region
§ Continue performing FOT (every 1.5 to 2 months) to capture TAP slug moving away from the injector (RF
effect), viscosity build up (activation / RF effect) and permeability reduction due to TAP adsorption /
retention (RRF effects). Frequency of tests is dependent on reservoir specifics and implemented treatment
o
•
•
•
SPE Number
11
§
•
Once FOT interpretation does not require major changes (e.g., TAP permeability effects suggest that
boundary conditions are holding) frequency of FOT can be extended to every 3 to 4 months to evaluate
possible treatment (thermal) stability of TAP vs. time
• Inferring TAP stability vs. time can be subjective because water can find a secondary channel (less
resistant path), which can make it difficult to confirm the stability of the treatment. However, FOT
interpretation combined with continuous water compositional analysis of produced water may
contribute to determining whether the treatment is still effective and/or define the timing for a second
treatment
o FOTs provide valuable data for evaluating TAP treatment. Pre-treatment FOT can be used to infer reservoir
permeability of the thief zone and post-treatment FOT can be used to evaluate the conformance
improvement. As TAP particles expand and build viscosity, particles start to adsorb to the rock surface or be
retained by aggregation or both, and partially block the pore throats of the swept zone. The combined effects
of viscous material and adsorption/retention increase the resistance to water phase flow and divert flow into
the unswept area of the reservoir. This phenomenon affects the flow regime and can be detected by a posttreatment FOT interpretation. This application of FOTs is an area of active review and evaluation and
additional details will be provided in a separate publication
Water composition analysis of produced waters to evaluate the following:
o Discard / confirm the presence of TAP production. This step is critical for TAP treatment success and meet
Safety Health & Environment (SHE) regulations country/company specific. The analysis of produced water
should be continued for as long as possible using qualitative and quantitative methods
o Evaluate possible changes in production water composition that may help to infer that oil production is coming
from unswept zones associated with high salinity /hardness formation brines where the brine composition make
this feasible.
Summary
This paper presents screening criteria, engineering approach for data evaluation and monitoring strategies to design and
implement a deep conformance improvement treatment. Summary of the major finding of this paper include:
• TAP is a deep conformance treatment and it does not affect reservoir injectivity. The thermally activated polymer is
adsorbed onto the rock surface or retained in pore throats and small pores, or both, and creates resistance against flow
(RRF) in the thief zone.
• There are two types of screening criteria; basic or decision-making screening criteria and ranking criteria. Basic screening
criteria are examined to evaluate a field’s potentials for TAP application. Extended screening criteria can contribute to
ranking of different patterns and well candidates for TAP applications.
• The analysis of injection and production data will help to identify well communication and presence of a channel between
injectors and producers. Two methods are used to estimate channel volume: 1) injection-production data analysis.2) transit
volume from numerical simulations.
• Two simulation approaches are proposed and are used to model characteristics of TAP. Currently both simulation
approaches are used to design TAP treatment. In the mechanistic approach, physical characteristics such as viscosity and
adsorption increase with heat and time and the rate of increase depends on the product grade and transit time in the thief
zone. In the kinetic approach, a temperature dependent kinetic reaction is used that accounts for time and temperaturedependent viscosity of TAP and its interaction (adsorption/retention) with reservoir rock. The reaction parameters are tuned
by laboratory bottle tests and adsorption/retention tests.
• To develop the proper treatment design and interpretation of TAP technology a baseline for data evaluation and monitoring
strategies is defined.
Acknowledgements
The authors would like to thank the reservoir engineering and laboratory research groups at TIORCO for technical support and
TIORCO management for support and permission to publish this work.
12
SPE160749
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