Proposed Module Flow
Design Objectives
Production time-series analysis has three reservoir-characterization objectives: determine the initial
reservoir drive mechanism, understand the effects of previous reservoir production strategies, and, most
importantly, understand how the reservoir architecture has influenced fluid flow. The combined influence
of these three factors is what has created the reservoir’s production history. Knowledge of their relative
effects is critical in reservoir characterization and in determining reserve-growth potential. To achieve the
objectives of production time-series analysis, five main tasks must be accomplished, preferably in the
order listed below:
1.
2.
3.
4.
5.
Analyze initial and spatial time variation of fluid chemistry.
Analyze initial conditions for fluid contacts from completion, workover, logs, and pressure.
Graph production and annotate along with production-strategy history.
Map and analyze time-series history of fluid production.
Determine flow direction of injected and encroaching fluids.
In this module, we will examine tasks 3, 4, and 5; graphing production and annotating production-strategy
history, mapping and analyzing time-series fluid production history, and determining flow direction of
injected and encroaching fluids. Module 12 covers the first two tasks to be accomplished when
performing production time-series analysis of a reservoir.
Knowledge Base
Compilation of Completion and Workover Information
The compilation of completion and workover information onto maps and logs is critical to understanding
effects of previous reservoir-production strategies and what portion of the reservoir the data are
associated with. Posting the initial completion date on a base map is the first step in compilation and
illustrates both the initial drilling pattern and the relative spatial timing of production. Next, logs should be
annotated with initial completion perforations and any subsequent reperforations and workovers, as well
as any known production data, such as production rates or cumulative fluid volumes. This information
illustrates which genetic units were perforated and produced, along with the timing and production
results. Next, completion intervals for each well are posted on the gross sand maps generated when
determining the reservoir architecture. This map shows the spatial distribution of completions within each
genetic unit and is a first look at possible missed pay zones.
Production Time-Series Graphing and Mapping
A time-series analysis of fluid flow consists of graphing and mapping of oil, gas, water cut, fluid levels,
and pressure-depletion variation over the producing life of a reservoir. Graphing of all produced fluids and
pressure is done on both the reservoir and well levels. Reservoir-level graphs illustrate the production of
all fluids and should also include the number of wells on line. The wells should be annotated with the
timing of any production strategy changes, such as the implementation of secondary or tertiary recovery.
Graphs are developed to capture the shortest interval in which data are taken and then are annotated
with any workovers that may affect the well performance, such as pumps, well stimulation, tubing
changes, and recompletions.
Next, fluid-flow trends within the reservoir are established from a set of production-performance maps that
illustrate initial potential, cumulative and current production, gas:oil ratio (GOR), fluid levels, water cut,
and pressure depletion on a per-well basis. Analysis of these maps captures the historical changes in
fluid production throughout the reservoir and highlights important trends in fluid flow. Areas of best
production (sweet spots), as well as areas showing impedance to fluid flow, are readily identifiable.
Water-cut and pressure maps record the pattern of water migration as reservoir pressures decrease and
can highlight preferential pathways of fluid migration. These patterns will most likely indicate fairways of
high transmissivity and, thus, reservoir communication. Anomalies in these maps can indicate barriers
to fluid flow, which may also indicate reservoir compartmentalization.
Four-dimensional seismic is a newly emerging technology in production time-series analysis. It involves
the recording of 3-D seismic at two different times in the production life of the reservoir and comparing the
differences. Any difference in seismic attributes observed occurs from a change in fluid saturation and
thus indicates fluid flow. For example, the encroachment of an aquifer or the expansion of a gas cap
could be interpreted from the seismic attributes.
Comparison of the initial hydrocarbon-fluid characteristics and the time-series analysis is the primary aid
in determining the initial drive mechanism. Monitoring GOR can indicate whether gas-cap expansion or
solution-gas drive, or both, are the functioning drive mechanism. Rapidly increasing GOR near the crest
of the structure can indicate gas-cap expansion in a reservoir containing initial oil characteristics at or
above the bubble-point pressure. A fairly uniform increase in GOR around the field can indicate a
solution-gas-drive mechanism and uniform pressure depletion. A time series of the water:oil ratio that
displays increases up structure over time can indicate a water-drive mechanism.
Another key is whether the oil in the reservoir is undersaturated or saturated with solution gas. An
undersaturated oil reservoir can produce substantial volumes of oil with a significant pressure drop before
gas will come out of solution in the reservoir. This situation will be seen in a steadily producing GOR at a
value near the initial-solution gas:oil ratio. In contrast, saturated oil begins to produce at elevated GOR's
soon after production with only a minor pressure drop.
Analysis of Pressure History (Step 1)
Pressure data can be valuable information in characterizing a reservoir for determining fluid flow
compartments. Pressure data are normally obtained from downhole measurement and/or measurement
at the wellhead. The pressure measurement desired is the reservoir pressure surrounding the well bore.
There are several difficulties to obtaining an actual reservoir pressure. The well must be shut-in a
sufficient length of time for the pressure to stabilize so that the measurement does not reflect a transient
state. Wells nearby, if not also shut-in, may cause interference from their drawdown, resulting in a
measured pressure lower than the actual reservoir pressure. If the well bore is open to more than one
production zone the measured pressure may reflect only the most permeable zone. Additionally, if the
reservoir pressure has been determined from shut-in wellhead measurements, unknown liquid loading in
the well bore may cause the calculated reservoir pressure to be less than the actual pressure.
One method of analyzing pressure history is through the concept of material balance. This concept states
that in a closed system the moles of hydrocarbons produced must equal the initial moles of hydrocarbons
minus the remaining moles (Beggs, 1984). This concept is readily used in the analysis of gas reservoirs
where pressure data are periodically measured. When the gas law is applied to this concept it results in
the linear equation below, where the x value is Gp and the y value is P/Z. Note that when P/Z (y value)
equals zero then Gp/G is equal to one. Therefore, a linear extrapolation of a P/Z vs Gp plot (materialbalance plot) to a value of P/Z equal to zero results in obtaining the original gas in place (G).
P/Z = -[Pi/(ZiG)]Gp + Pi/ZI ,
where
P = pressure
Z = gas-compressibility factor
I = initial oil in place
G= original gas in place
Gp = cumulative gas produced
Gas-material-balance plots, if correctly interpreted, can give valuable information about reservoir
character and fluid flow. Characteristics are interpreted from the shape of the material balance plot. (Fig.
1). Changes in the gas-material-balance plots can occur from two sources. The first source is the effect
that reservoir-production practices can have on the material-balance plot. For example, a new well drilled
in a gas field can change the drainage pattern of the existing well causing "interference," which can
reduce the effective drainage area of the existing wells. This interference will cause the slope of the line
on the material-balance plot to decrease, reflecting the reduced effective-drainage volume. Perforating a
new zone can result in an abrupt increase in the material-balance plot as the pressure from the newly
perforated zone increases the overall pressure.
Reservoir characteristics are the second control on change in the gas-material-balance plots. The
volumetric depletion of a single reservoir compartment results in a straight line that can be extrapolated
down to 0 P/z to determine the original gas in place. If, however, a well is perforated in multiple zones that
contain highly variable permeability, the resulting material-balance plot will likely not be straight. The
more-permeable zones will deplete first, followed by the less-permeable zones, resulting in kinks on the
line. The initial drive mechanism also affects the material-balance plot. An aquifer drive will give pressure
support to the reservoir, causing the material-balance plot to curve and flatten out at the pressure-support
value. Abnormally high pressure (geopressure) can cause the material-balance plot to not decline as the
expansion of the sediments occurs, followed by a rapid decline reflecting the depletion of the
compartment. See the examples below. (Add links to text and figures)
Figure 1
Pressure History Exercise (Step 2)
The Lisa # 1 well was completed at 7,800 ft with an initial pressure of 3,435 psi. The production and
pressure depletion over the next several years is shown in the table below. Using this information, input
the pressure values shown in the table below into spreadsheet5-2.xls (gas gravity), to generate the
gas-compressibility coefficient for each pressure and to complete the table below.
Well name:
Lisa # 1
Cumulative
production
(MMscf)
Pressure
Gas(p)
compressibility
coefficient (z)
0
3435
100
3000
400
2700
700
2500
1100
2300
1600
2200
Once you have completed these steps, a material-balance plot will be automatically generated on the
basis of your answers. Study this plot to answer the following questions. For additional help, select Ask
the Expert.
Well name:
Lisa # 1
Cumulative Pressure
Gasp/z
production
(p)
compressibility
(MMscf)
coefficient (z)
0
3435
0.8798 3,904
100
3000
0.8666 3,462
400
2700
0.8624 3,131
700
2500
0.8620 2,900
1100
2300
0.8636 2,663
1600
2200
0.8652 2,543
Graph filled in with results:
This plot is automatically generated on the basis of your answers in the table.
1. Does the gas-compressibility factor change linearly as pressure decreases?
2. What is the estimated original gas in place (OGIP) from this material-balance plot?
Add Expert Warning here if values do not match exact graph.
3. From analyzing the pressure and production history, what reservoir characteristics can be
inferred?
Ask the Expert (1)
At a constant temperature the gas-compressibility factor is not a linear factor but instead varies in a
parabolic manner. An OGIP (original gas in place) could be estimated for these data, but because the plot
is somewhat concave, it is likely that these data reflect pressure maintenance because of an active
aquifer drive.
(Add the answers to the 3 questions here)
Water-Production Analysis (Step 3)
Water production is one of the most critical fluid-flow trends to understand when identifying reservegrowth potential. The production of water can indicate encroachment of an aquifer, rendering portions
of a reservoir void of reserve-growth potential. However, water can often finger or channel into the
productive interval, leaving substantial reserve-growth opportunities behind. The risk of additional
reservoir development can be substantially reduced when detailed water-production analysis is
incorporated into a reservoir-characterization model.
Characteristics of Aquifer Encroachment
Aquifer encroachment decreases ultimate recovery in gas reservoirs. Encroaching water traps residual
gas behind the invading water front and maintains reservoir pressure. These effects reduce the volume of
gas that will be produced, as compared with conventional pressure depletion. Also, as water volume
flowing into the well bore increases, loading can eventually occur, which will effectively kill the free flow of
gas, resulting in down time, sporadic well production, costly well maintenance, and, ultimately,
abandonment of the well. Additionally, high volumes of produced water can increase disposal costs,
rendering a well uneconomic. Careful planning, design, reservoir characterization, and well handling are
needed to maximize gas recovery when aquifer encroachment occurs.
Oil reservoirs, in contrast to gas reservoirs, can benefit from aquifer encroachment. Water encroachment
from a connected aquifer can act as a water drive, maintaining pressure and displacing oil. The
maintenance of pressure sustains flow rates, and the displacement of oil by water increases sweep
efficiency. Again, if water encroachment is irregular, however, substantial oil can be bypassed, resulting
in poor recovery.
Aquifer and hydrocarbon-reservoir characteristics and production history govern water encroachment,
and understanding these factors is critical to optimizing oil and gas recovery. The main aquifer attributes
that influence a hydrocarbon reservoir are aquifer size, pressure, and geologic character. Size and
pressure characteristics affect the pressure support transmitted to the hydrocarbon reservoir. The larger
the aquifer relative to the hydrocarbon reservoir (dimensionless radii), the greater and longer the
pressure support and the higher the recovery efficiency in oil reservoirs. A greater pressure differential
between the aquifer and a depleting gas reservoir can reduce ultimate recovery. Recovery efficiencies for
gas reservoirs and aquifers at lower initial pressures will be less affected by aquifer encroachment,
whereas higher pressure systems may result in faster water encroachment (Agarwal and others, 1965).
Permeable and homogeneous aquifer/gas reservoir systems undergo faster water encroachment at
higher reservoir pressures and thus have lower gas recovery efficiency. Also, higher residual gas
saturation resulting from poor geometry and higher relative permeability to water will lead to lower
recovery efficiency. High residual-oil saturation occurs when pressure depletion is not uniform in the oil
leg and when the oil has high viscosity relative to the encroaching water. Overall, characteristics that
promote water influx and decrease oil or gas reservoir incremental pressure drop cause lower recovery
efficiency. See Figure 2.
Production history also influences aquifer encroachment. An increased gas production rate can result in
an increased recovery of gas (Agarwal and others, 1965; Matthes and others, 1973; Lutes and others,
1977). An increased production rate often leads to greater pressure depletion before wells water out, thus
resulting in greater gas recovery. The performance parameters proposed by Hower and Jones (1991)
illustrate the interrelationship between gas flow rate and reservoir characteristics. High production rates,
however, must be designed so that no coning or fingering occurs. Relative permeability and residual gas
saturation are important considerations in judging the effectiveness of higher production rates.
Permeability, relative permeability, and residual gas saturation characteristics affect the broadness of the
pressure gradient between gas reservoir and aquifer. A broad pressure gradient will increase the waterinvaded zone and result in a larger volume of trapped gas. Oil recovery is increased when reservoirpressure depletion is uniform. This uniformity reduces water fingering and, thus, bypassed oil as the
aquifer waterfront encroaches.
Interpreting Field Data (Step 4)
Determining the movement of water into an oil or gas reservoir characterizes the aquifer/hydrocarbon
reservoir interaction and aids in reservoir development. Modeling the direction of encroachment is best
accomplished by analyzing water/gas ratios (WGR), reservoir pressure, oil—water cut (percent water),
downhole production logging-tool response (spinner tests), and produced-water characteristics in a time
series of maps. This analysis is dependent on monitoring data at short time intervals so that significant
trends can be observed. Map time-series observation facilitates determination of fluid movement in three
dimensions and integration of geology and engineering, and it aids in reservoir simulation. Increases in
WGR can occur as a result of four different scenarios: (1) water coning or fingering, (2) reservoir
communication with a small passive aquifer, (3) reservoir communication with a strong aquifer, and (4)
communication with a water zone behind casing. Figure 3 demonstrates these concepts. (Qac784c)
An increasing water:hydrocarbon ratio (WHR) is the first phenomenon signifying a water-production
problem and possible aquifer encroachment. At the onset of increasing WHR, the possibility that water
coning or fingering is occurring in a single well must be suspected. Either of these occurs when a well
bore pressure drawdown is high enough to cause a local change in the hydrocarbon—water contact
(HWC) such that it comes in contact with the well bore. Reservoirs that have good permeability and/or
high permeability heterogeneity are most susceptible to coning and fingering. Diagnostic features of
coning or fingering include rapidly increasing WHR or WHR increasing in only one well while others at
structurally equivalent positions show no WHR increase (water crosscutting structure). This crosscutting
of structure can occur in multiple wells. Coning or fingering may occur when WHR increases rapidly
immediately after drawdown on a well has been increased. In some cases, production logging tools can
identify whether water is coming from the lowest perforations. A time series of WGR or WOR maps will
show a rapid increase in WGR or WOR in localized spots (like bull’s-eyes). Over time, WHR will increase
in those wells that have coning or fingering problems.
WHR can also increase when a passive or small aquifer is connected to a reservoir (no water drive or
only a weak one). In this scenario, a steady WHR increase will occur with a large drop in overall reservoir
pressure over an extended period. Aquifer encroachment will gradually follow up structure, with the
hydrocarbon—water contact rising on a reservoir scale. Local variation in permeability may cause faster
localized WHR changes; however, it is unlikely that water encroachment will crosscut structure
significantly.
A strong water-drive aquifer can cause the WHR to increase early in the production life of a reservoir.
Encroachment of water will follow up structure, increasing the WHR over time, corresponding to overall
reservoir pressure drop and cumulative hydrocarbon production.
The final scenario that can increase WHR is communication with a water zone behind casing. Water
problems occur when poor casing cementation permits water to move between casing and formation. If a
water-behind-casing problem results from a poor cement job, the initial WHR may be high and the well
may appear to have been completed in the hydrocarbon/water transition zone. When the cement job
deteriorates over time, WHR may increase slowly. Water-behind-casing problems can be diagnosed
when increasing WHR does not correspond to reservoir cumulative production or pressure changes or
when the problem is localized and as a result does not occur in other nearby wells.
Monitoring and analyzing reservoir pressure can determine whether water problems are related to one of
the four scenarios described earlier and can indicate direction of water influx. Aquifer encroachment
causes the rate of pressure depletion to decrease over time with increasing cumulative production.
Neither coning and/or fingering nor increased WHR from water behind casing will provide pressure
support. A passive aquifer will provide little pressure support.
By mapping and interpreting material-balance plots in gas reservoirs, the area for which pressure support
is occurring can be determined. Figure 1 illustrates the effect different reservoir characteristics have on
material-balance plots. Strong evidence of pressure support is provided when the pressure support
corresponds to rapid increases in WHR up structure. The direction of increasing WHR and pressure
support illustrates the direction of water encroachment.
Production logging tools (spinners) can also assist in determining the characteristics of water production.
These tools demonstrate what water volume, different perforations, and/or sandstone zones contribute to
total water production. When water is coming almost exclusively from upper perforations, communication
with a water zone behind the casing should be suspected; when only the lowest perforations are
contributing to water production, however, coning or fingering should be suspected. A specific reservoir
sandstone connected to an aquifer may be isolated in the case of multiple sandstone zones. Information
gained from production logging tools can guide the use of dual completions, permeability profile
modification, and/or selective perforation plugging.
Monitoring produced-water chemistry can indicate the origin of water and thus aid in determining water
fluid-flow trends. Changing water chemistry should be analyzed over time and between wells. Freshening
of produced water may indicate communication with a water zone behind the casing above the reservoir
(water dumping), whereas increasing salinity may indicate production from an aquifer that is more saline
than the connate water. Proper interpretation can be accomplished only when the specific reservoir water
chemistry (as well as that of the overlying and underlying aquifers) is known.
Aquifer Encroachment Exercise (Step 5)
The reservoir-characterization team has delineated a correlatable fault-bounded genetic unit. Now the
aquifer encroachment needs to be interpreted and the team wants to test whether this genetic unit is
acting as a flow unit. The production data are to be analyzed in order to answer these questions. First, a
time-series analysis of water production is to be performed. The production rate vs. time graphs (5 FlowUnit History Graphs) for oil rate and water cut are provided. Also provided on a map (b3400 structure
map) are subsea structure and depth of lowest water production. Use the map and graphs to complete
the table (Solution to Aquifer Encroachment Exercise), and determine the timing of initial water
breakthrough and the changes of water cut over time.
Well
name
Date of 1st
production
Depth of
lowest
perforation
(feet ss)
308
310
309
313
329
Look at the map to fill in Depth of lowest perforation and the five graphs in order to put in the Date
of 1st production.
Now that you have completed the table, answer the following questions. To review the correct results, or
for additional help, select Ask the Expert.
1.
2.
3.
4.
What is the order in time of water breakthrough for these wells?
Does structure affect the encroachment of water?
Should the reservoir characterization team consider this genetic unit a flow unit?
When well 329 was drilled and completed in June 1991 did it initially produce water-free?
Ask the Expert (2)
1. By creating a table of well name, date of first water production and subsea depth of lowest
perforation, the order of water break-through can be determined. By mapping the date of first
break-through along with the depth of lowest perforation onto a structure map, the movement of
water can be assessed.
Well
name
Date of 1st
production
Depth of
lowest
Notes
perforation
(feet ss)
308
January 1970
-3871
Produced water after
1 month of production
310
October 1970
-3869
Produced water after
1 month of production
309
October 1983
-3797
13 years w/o water
producing 3.4
MMSTB
313
July 1990
-3734
Produced water after
2 months of
production
329
October 1991
-3784
44% water cut for IP
2. Within this area the structure sand-body geometry and production are controlling aquifer
encroachment. Water is encroaching up structure from the northeast to the southwest; however, it
reached its structural high in the southwest corner before the northwest corner (well 309). This
fact indicates that structure alone is not influencing aquifer encroachment.
3. The water encroachment trend indicates that it is likely that this genetic unit is in fluid-flow
communication and can therefore be interpreted as a fluid-flow compartment. Figure 4
demonstrates this point.
4. No. From the subsea depths of water encroachment, it is as if the aquifer had encroached up to
the depth at which well 329 was perforated.
References
Agarwal, R. G., Al-Hussainy, R., and Ramey, H. J., Jr., 1965, The importance of water influx in
gas reservoirs: AIME, Journal of Petroleum Technology, November, p. 1336–1342.
Beggs, D. H., 1984, Gas production operations: Tulsa, Oklahoma, Oil and Gas Consultants
International, Inc., 304 p.
Hower, T. L., and Jones, R. E., 1991, Predicting recovery of gas reservoirs under waterdrive
conditions, in Society of Petroleum Engineers 1991 Annual Technical Conference and Exhibition,
Reservoir Engineering Proceedings, SPE No. 22937, p. 525–540.
Lutes, J. L., Chiang, C. P., Rossen, R. H., and Brady, M. M., 1977, Accelerated blowdown of a
strong water-drive gas reservoir: Journal of Petroleum Technology, December, p. 1533–1538.
Matthes, G., Jackson, R. F., Schuler, S., and Marudiak, O. P., 1973, Reservoir evaluation and
deliverability study, Bierwang field, West Germany: Journal of Petroleum Technology, January, p.
23–30.