Issues in Waterflooding III — Introduction to Waterflood Surveillance
Posted by D Nathan Meehan November 11, 2010

Consistent gathering and analyzing of the data relevant to waterflood performance is called waterflood surveillance and it has many forms. Simply measuring and recording phase rates and pressures is an initial step. Unfortunately many waterfloods rely on relatively infrequent well tests of individual wells to allocate production that is gathered and measured at any of several locations with higher frequency. Total oil production is usually known with a fair degree of accuracy. In modern oilfilelds total produced gas can be calculated with reasonable accuracy because flaring and venting is now (fortunately) a rare practice and even gas used for fuel is measured.  This is not always the case with historical data. Produced and injected water volumes should also be known with accuracy; historical water data may not be so reliable. Common surveillance methods will be discussed in this and in subsequent blog posts. One of the most fundamental methods of surveillance is understanding voidage replacement. The concept is simple. Compare what goes in to what comes out.  In this entry I also discuss the ABC plot.

Voidage replacement

Voidage replacement refers to replacing the volume of oil, gas and water produced from the reservoir by injected fluids. Voidage replacement ratio is the ratio of reservoir barrels of injected fluid to reservoir barrels of produced fluid. Mathematically (for water injection) it can be expressed as

In this equation, Bα,  qα and iα are the formation volume factors, production and injection rates for phase α. GOR is the producing gas-oil ratio and Rs is the dissolved GOR. The third term in the denominator accounts for “free gas” produced that is in excess of that gas in the reservoir that is dissolved in the oil.

The voidage replacement ratio can be calculated on an instantaneous basis using injected and produced fluids over any specific time period (typically daily or monthly) or on a cumulative basis by using the cumulative injected and produced fluids. In the case of the cumulative voidage replacement ratio, it is common to start the cumulative production numbers at the commencement of waterflooding. Some authors have used cumulative data starting at fillup (the point at which injected water is estimated to have filled the available gas saturation in the reservoir).

Values of voidage replacement ratio less than unity are remarkably common in mature waterfloods.  In such cases it is also typical to observe declining oil production rates, increasing water cuts and increasing GORs along with declining reservoir pressures. Voidage replacement ratios above 1.0 are necessary prior to fillup and most waterfloods target operating at about this level during the economic course of the waterflooding process. Many waterfloods operate well above a voidage replacement ratio of 1.0 (some as high as 2.0 or higher) for years.  Invariably this implies out of zone injection and is often associated with highly fractured reservoirs, poor quality cement bonding or other sinks for water injection other than the desired reservoir.

Voidage replacement maintained at 1.0 does not mean that the reservoir is being operated at constant pressure. Pressure is not conserved in the sense that material balances of fluids are conserved. More importantly, a reservoir wide voidage replacement ratio of 1.0 does not mean that the flood is being effectively managed. Voidage replacement ratio should be tracked not only at the field level but by reservoir, by fault block and even by pattern. Streamline models are often particularly useful to supplement voidage replacement tracking.

ABC plots

Terrado et al (M. Terrado) described a method of quick analysis for a large number of wells undergoing waterflooding that they refer to as the After-Before-Compare (ABC) plot. This simple tool only requires knowing the oil and water rates for a certain group of wells at two different dates. This tool can be used for a wide variety of other monitoring applications; the authors suggest that injection wells can be analyzed by plotting the injection rates and pressures at two separate dates. In practice a fixed time period difference is selected and the ratio of the oil rate at time 2 divided by the oil rate at time 1 is plotted on the abscissa while the water rate at time 2 divided by the water rate at time 1 is plotted on the ordinate as shown in the following example figure.

In the following example the values for time 2 are three months after the values for time 1.  In a stable flood there should be many data points near (1,1). In this example there are a lot of data points with Most of the data points fall with approximately constant water cuts (as indicated by being near the unit slope line passing through (1,1). Wells in the upper right quadrant show both increasing water and oil production (increasing total fluid) and roughly constant water cuts. This can indicate a positive response to water injection or changing artificial lift conditions. Wells in the lower left quadrant show decreasing total fluid production and nearly constant water cuts. These wells should be examined to determine if the decreased fluids are due to changes in artificial lift, wellbore damage or other reservoir issue. These wells may indicate easy targets to increase production.  Wells in the lower right show increasing water production with constant or decreasing oil rates. While all wells will ultimately show this behavior, sudden jumps in water rates could indicate channeling. Wells in the upper left quadrant show increasing oil rates and decreasing water rates.  In mature fields there may not be many wells with this behavior; in EOR projects, this may indicate positive flood response.

In this specific example the wells the production engineer wishes to examine in more detail are shaded in and have a slightly larger diameter. More information can be conveyed in ABC plots by adding different color, symbol types, etc. to indicate geographical areas, completion types, gathering systems, etc. The operator in this particular field (actually a specific fault block) also observed a group of five wells that also appeared to have a unit slope passing through approximately (1.7, 1.0). What might cause this?

Figure 1 ABC Plot showing quick method for waterflood surveillance

Works Cited

M. Terrado, S. Y. Suryo Yudono, and Ganesh Thakur, Chevron Energy Technology Company (24-27 September 2006). “Waterflood Surveillance and Monitoring: Putting Principles Into Practice”, SPE 102200-MS. SPE Annual Technical Conference and Exhibition. San Antonio, Texas, USA: SPE.

15 responses | Add Yours

Responses

Artyom Galimzyanov says:

thank you for this article. This ABC plot is very easy thing but can provide valuable information and help us to get clear understanding of our reservoir.

Bryson Wolfe says:

Nathan,

You said that the ABC plot can be applied to EOR projects, does this include WAG floods with CO2? You also posed at question at the end of the blog as to what might have caused the deviation from the unit slope line passing through (1,1). Is this due to possible channelling due to the fault or natural fractures in the reservoir?

D Nathan Meehan says:

For sure the method can apply to WAG with CO2 or any other injected fluid but does need to be modified somewhat. the y-axis is usually still the same, plotting the oil production rate ratios. However, the water ratio timing may need to be carefully selected or the x-axis and ratios use reservoir barrels. In that case the producing gas-oil-ratio (Rp-Rs) is used in the numeratior of the x-axis.

I have even made the plot a simple 3-D plot by color coding the plots based on GOR (after) and characterizing their shape as different symbols.

I think there is a better and more common explanation for the five wells. Hint: they are in the same part of the field.

Bryson Wolfe says:

Looking at the graph the 5 points indicate an increase in water cut and since they are in the same part of the field might decrease the likelihood that they are channeling because they all fall on the unit slope line passing through (1.7,1). Since water cut usually increases as the field matures could it be that these 5 wells are showing the expected behavior of a waterflood asset?

Rodolfo Galecio says:

Following the reasoning behind the unit slope line, these five wells share approximately the same water cut, then what are the shared geological feature or features able to produce such behavior?

Basel says:

Hi Nathan,
you said:
“Voidage replacement maintained at 1.0 does not mean that the reservoir is being operated at constant pressure”
How is that possible? Could you please clarify?
Thank for the great article.

D Nathan Meehan says:

I thought someone might catch that. The thing to keep in mind is that the relative amounts of oil, gas and water are changing in the system. Unit voidage replacement means that 100% of the produced fluids (in reservoir volumes) are replaced by equivalent reservoir volumes of injected water (fluid). Imagine 100 RB of oil (and dissolved gas) are the only things present in the pore space at time 0. Then, when 50 RB have been produced, 50 RB of water is injected. Does the reservoir pressure remain constant? No, there is a slight change due to the differences in fluid compressibility. In most cases, in order to keep the average reservoir pressure constant, a slight difference in the amount of water is required (a few percent). As water cuts increase and the water saturation of the reservoir gets larger and larger, this difference decreases. This is more noticeable in the case of gas injection.

While it is a bit of a difficult concept to get one’s head wrapped around, the important concept here is that pressure is not conserved. BTW, I leave it as an exercise to see whether more than 100% or less than 100% is required to maintain constant pressure. If you like, this is easy to test in a simple simulator. I leave it as an exercise and if someone makes a very nice demonstration we can post it here.

raghu says:

can we use these ABC plots for gas fields too?

raghu says:

can we use these ABC plots for gas fields too? if yes which variables should be taken for plotting? and how to interpret the plot for gas fields?

D Nathan Meehan says:

Raghu

Nice observation. We could use a similar plot, but remember that this plot is comparing total fluid (at two dates) and oil (at two dates). In a gas field we could certainly look at gas rates at two dates but what would you plot on the other axis? I have plotted FTP(t1)/FTP(t2) or even calculated (or measured) BHP ratios but the data tend to cluster around 1.0 unless there has been a significant change. Again, the “natural order” of waterflooding suggests certain movement on the ABC plot while in a gas field there is generally declining PI and ultimately rates.

I have plotted calculated PI ratios and rate ratios as a diagnostic plot and I assume you could come up with other ideas. While I do not think they might be as powerful tools as this I encourage the readers to “think out of the box” and see what other diagnostic tools might be useful. I particularly think that in rapidly declining wells we might have some room to run with the PI ratios….

raghu says:

thanq meehan for your valuable suggestions……. i would also plot gas ratios Vs FTP/BHP ratios….. and what about the interpretation?? if the points fall on upper right quadrant does it mean both gas rate n FTP/BHP is increasing????
and please i will be really happy if u could suggest me any other methods for analysis of gas well reservoirs…

raghu says:

Does FTP mean flowing tubing head pressure(FTHP) or anything else?? please specify……………

D Nathan Meehan says:

FTP does mean Flowing Tubing Pressure also abbreviated FTHP. As to the meaning of the various plots I am going to have to suggest that is beyond the scope of the blog responses as it would take quite a bit of detail. If I find a good reference I will send it. Thanks

Alex Renaud says:

Regarding the question that Basel posed on May 13, 2011 at 6:53 am: Average reservoir pressure may not be maintained at a constant pressure with a (cumulative) VRR maintained at 1 also due to injection losses. This means if 100 bbl/d of water is injected at an assumed 15% loss factor, only 85 bbl/d of the water is assumed to contribute to the waterflood (with the other 15 bbl/d of water lost to some high perm streak, to an aquifer, or to some other place that does not support the flood front).

D Nathan Meehan says:

Of course pressure will drop if injected fluids leave the reservoir. But even with no losses, pressure is not conserved due to differences in fluid properties. Thanks

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