oil and gas

DOTI PAPER 141

Deepwater Evaluation Performing a DST Test for Heavy‐Oil Reservoir in the Marine

Region of Mexico

Jan Loaiza‐Halliburton

Daniel Barrera‐Pemex

Francisco Gutierrez‐Pemex

2 DEEPWATER EVALUATION PERFORMING A DST TEST FOR HEAVY‐OIL RESERVOIR DOTI 141 IN THE MARINE REGION OF MEXICO

Abstract

The plans used to develop new reservoirs depend largely upon information obtained from well

tests. These tests involve taking measurements during steady-flow conditions in order to

measure flow rates and record the bottomhole pressures (BHP) in the new reservoirs.

In heavy-oil environments, however, it is difficult to have natural flow because of the high

viscosity, low permeability, and in some cases, the low temperatures inherent to heavy oil.

Performing drill-stem testing (DST) evaluation in heavy oil reservoirs with very low API gravity

and static pressure normally will require artificial lift to flow the oil to surface; the methods

normally used to perform the artificial lift are electric submersible pumps (ESPs) or coiled tubing

to pump diesel at bottom during evaluation. Unfortunately, these methods might not be cost

effective for the project.

An alternative test method for evaluation is to inject fluid into the reservoir instead of

flowing the well. This method, known as the injection pressure test or fall off, offers several

advantages, because it can reduce costs and increase pressure-data quality. This type of test

offers short-time evaluation capability and improved quality of information. Economic

advantages are realized from elimination of artificial lift equipment and coiled tubing.

With injection tests, it is not necessary to use surface equipment in order to measure the

production flow rate; also, fluid-collecting vessels can be used, which further reduces the costs of

assessment.

In order to test a well using DST in injection conditions, an injection period with a constant

injection rate is needed in order to generate a pressure disturbance into the reservoir as well as oil

displacement; after the injection period, downhole shut in with a tester valve is needed. Data

obtained during falloff are processed with pressure transient analysis to determine the following

parameters:

• Static pressure of the reservoir

• Effective hydrocarbon permeability

• Formation damage

• Boundary effects (conductivity faults, non-conductivity faults, fluid contacts,

heterogeneities, etc.)

DOTI 141 JAN LOAIZA, DANIEL BARRERA, and FRANCISCO GUTIERREZ 3

This paper discusses several case histories in which successful DSTs were run using the

injection test method.

Introduction The characteristics of heavy oil are largely dependent upon the pressure and temperature at

bottomhole reservoir conditions; most of the time, these conditions hinder well-test evaluation

because of the natural flow conditions at surface (Matthews, C.S.. et al, 1954) (Earlougher, R.J.,

1977). One alternative used to flow the heavy oil from the bottomhole to the surface is an

Electrical Submersible Pump (ESP), which is placed in the DST tool string. This alternative

provides the flow stimulus for the reservoir and therefore facilitates performing a reservoir

evaluation using the conventional reservoir engineering calculations. However, this alternative

can require significant amounts of rig time to rig up, RIH, POOH, and rig down and there may

be added risks to the equipment from downhole faults.

Depending on the availability of a rig, it is possible to evaluate the reservoir through a DST,

which is a temporary completion of a well for evaluation purposes. The most important tools in

the DST tool string are the temperature and pressure gauges that record the bottomhole pressure

and temperature, the tester valve that allows the downhole shut in to be performed, and a

retrievable packer. Using this arrangement allows pressures and temperatures near the reservoir

during the static and dynamic periods in the evaluation to be captured. In the case history wells,

the gauge information was processed, analyzed, and interpreted in order to obtain reservoir

parameters that could characterize the area of influence of the well. This type of well test can be

divided into two groups, based on flow conditions:

Pressure-Production Test

• Drawdown

• Build-Up

• Back pressure test

• Isochronal test

• Modified Isochronal test

• Interference test

• Multirate test


Injection Test

• Fall-Off

In Pressure-Production Tests, it is necessary to measure the flow rate at surface conditions

and to maintain a constant flow rate, and to collect the reservoir pressure response during the

production period. After the production period, it is necessary to shut in the well in order to

record the pressure behavior of the reservoir for analysis.

The pressure response during the build-up test depends on the total skin and the wellbore

storage effect; the semilog plot, “Horner method,” can be used in order to obtain the rock

parameters as effective hydrocarbon permeability and static pressure. During the evaluation of a

DST test in flow conditions, it may be necessary to employ the following services and

operations:

1. Process fluid ships

2. Coiled tubing

3. Induction operations

4. Surface equipment in order to measure the flow rates

5. Well-kill operations (in order to recover the tool string).

All the services and operations that are associated with the production operations and well-

kill operations involve operative costs and long periods of rig time.

One operational alternative used in order to obtain representative reservoir data with reduced

operating expense is to employ an Injection/Fall-off Test. In this type of evaluation, it is not

necessary to recover the heavy oil at surface, thus, simplifying the operations. The Injection/Fall-

off tests consist of an initial injection period with a

constant injection rate after the injection period. If

it is necessary, a downhole shut in is performed.

The start of the injection/fall-off test operation is

similar to a build-up test; i.e., a dynamic period

with a constant flow rate, and after that, a shut-in.

The injection pattern is shown in Figure 1.

WellWater Zone Oil Zone

Transition zone

Kw, μw, Ctw

Ko, μo, Ct

Static Pressure Zoneor Non-affect zone

Figure 1 ─ Injection Pattern in a Fall-Off Test


Figure 1 shows the vicinity of the wellbore zone in which the injection fluid is situated.

Here, one of the most important reservoir parameters, total skin, is calculated. The next zone

(inside the reservoir) is a transition zone or "the sweep zone," and then, there is the oil zone.

This is the zone from which it is possible to obtain the effective oil permeability, and finally, in

the non-affected zone, the static pressure of the reservoir can be calculated.

The combination of the parameters obtained from the injection/fall-off test as well as fluid

properties make it possible to obtain the sweep efficiency and other displacement parameters that

might be useful in future projects for secondary recovery.

The magnitude of the injection rate and the total volume of fluid that can be pumped depend

on reservoir parameters such as porosity, net pay, type of hydrocarbon, fracture gradient, etc.

The time of shut-in is simulated and depends on the rock characteristics and the fluids present

inside the reservoir. In order to avoid effects such as wellbore storage, when there is low

reservoir pressure, a downhole shut in is recommended.

Model Interpretation Assuming that the reservoir is homogeneous and isotropic, the injection-fluid and reservoir-fluid

properties do not change; gravitational effects are negligible, and with the help of the

characterization of the zone with the injection fluid as well as with the zone with the displaced

fluid, it is possible to obtain parameters that define sweep fluids; i.e., the mobility (M) and

diffusivity (D) relationships (between the zones with injection fluids and the zone with reservoir

fluids). (Soliman, M.Y., 2000)

The analysis of the injection/fall-off test is similar to the build-up test. It is possible to apply

the superposition method (Horner method) in which the dimensionless pressure “pD” is

expressed as follows:

pD(shut-in) = pcD( tiD + ΔtD ) – pcD (ΔtD) (1)

where:

tiD is the injection time

ΔtD dimensionless time (shut-in).

The response of the derivative curves in the injection-fluid zone as well as the reservoir fluid

will depend on the values of M and D, as shown in Figure 2 below:


Figure 2 — Log-log plot in Fall-Off Test

The behavior of the semilog plot in the fall-off test is shown in Figure 3 below.

Where P* corresponds to the average static pressure in the sweep area that already considers

the injection.

Figure 3 — Semi‐log Plot in Fall‐Off Test

Pressure Change

DerivativePressure

-7 -6 -5 -4 -3 -2 -1

5100

5200

5300

5400

5500

5600

5700

5800

Semi-Log plot: p [psia] vs Superposition Time

Parameters obtained from Oil zone :P* = Static PressureKh= Flow capacity

Parameters obtained from injecting fluid zone :S = Total Skin factor


Productivity Analysis Once obtained, the values of total skin (in the injection-fluid zone), effective hydrocarbon

permeability, and the static pressure “P*” (in the reservoir-fluid zone) with the help of other

reservoir parameters such as net pay, porosity, PVT data, and the downhole equipment

description (casing and tubing details) make it possible to conduct a productivity analysis,

assuming the well is in production conditions.

Once the well has been

completed, the productivity

analysis predicts the production

conditions of the well with several

scenarios; although some para-

meters used in the productivity

analysis come from the fall-off

test, the dynamic conditions are

representative of the well. This is

one of the main benefits of this

type of injection test. (Figure 4)

Pressure-Production Assessment with DST Tools and Heavy-Oil Reservoirs

In heavy oil reservoirs, there are great challenges to overcome in order to have a stable surface

flow rate during the assessments in terms of production. Despite the high viscosity of heavy oil

reservoirs, the bottomhole conditions (BHT and rock properties) make it possible to have enough

flow capacity into the well at the beginning of production; however, due to the decrease in

temperature and the increase of the viscosity, the natural flow to the surface will be hindered.

In some situations (depending on the oil API gravity), flow may not reach the surface due to

the adverse natural conditions; in the cases of offshore reservoirs where the lower temperatures

are at seafloor, these conditions can result in an increase in the viscosity of the fluid, which can

be the cause of the flow limitation. These scenarios present the most difficult challenges in

conducting a heavy-oil DST test. (Wendler, C., et al., 2004)

Considering the complexity in achieving a constant natural flow at surface, in most cases, it

is necessary to use an artificial lift method. The most commonly used method is the electric

Inflow�S = 7.79 Inflow�S = 0.0 Outflow�WhdChk ID = 20.00 Outflow�WhdChk ID = 32.00 Outflow�WhdChk ID = 40.00

FLOW RATE (bbl/d)6000500040003000200010000

FLO

WIN

G B

TM P

RES

(psi

g)

12000

10000

8000

6000

4000

2000

Inflow/Outflow Plot

5/16”

1/2”

1/2”

Skin= 7.79Skin= 8.0

Figure 4 ‐ Inflow / Outflow plot


submersible pump (ESP), which allows high constant flow rates to be captured at surface.

However, this method increases operational costs for the operator due to long periods of rig time;

also, the ESP requires the use of electrical cables as well as possible chemical injection lines and

other accessories.

Another artificial lift method that allows assurance of constant flow rates would be coiled

tubing with a Venturi jet pump or a simple injection of chemicals at bottomhole conditions that

would help to lift the fluid; however, there are limitations associated with the latter method, since

the production rates at surface are low, and problems related to the separation of phases at the

surface can occur.

Nitrogen injection at bottom in reservoirs with low static pressures using coiled tubing also

has limitations when the oil gravity is less than 12 API; experience has shown that in these cases,

it is not possible to break the inertia of the oil above the injection point that takes the injection

medium into the reservoir. Another big risk in DST test assessments under production conditions

in heavy-oil reservoirs offshore is that when the build-up starts, the oil temperature decreases due

to the stopping of the oil movement as well as the low temperatures associated with the seafloor.

Depending on how low the oil gravity is most of the time, when this cooling occurs, it may not

be possible to circulate out the oil on well-kill operations, which is required to recover the tool

string. All the factors mentioned above result in potential problems when attempting to obtain

reservoir information that is of high quality, is reliable, and is really representative of the

reservoir.

Fall-Off Assessments with DST Tool Strings in Heavy Oil Reservoirs – Applications

Traditionally, injectivity tests have been used mainly for the evaluation of secondary recovery

projects in which it is possible to obtain parameters that characterize the efficiency of the

recovery method. Actually, injection tests are still used for this function; however, other

applications have been added. One of these new applications, evaluation of heavy oil reservoirs

and wells completed as producers, was used in the case studies presented in this paper.

In cases where the characteristics of the well, formations and fluid type hinder the assesment

of the production conditions, an injection test using DST is an alternative method to evaluate the

reservoir. Following are the main applications where injection/fall-off tests can be used as an

alternative assessment for heavy-oil reservoirs:


1. In wells where the high viscosity of the oil (at surface conditions) increases operational

expense because of the low mobility, low pressure, and high removal rate of the oil.

2. The evaluation in terms of production requires the availability of a process ship. This

additional vessel is used to receive all fluids from the evaluation such as drilling mud,

control fluids, diluting fluids and reservoir fluids, such as water and oil. In cases that for

reasons of logistics, there is a lack of availability for this boat, a fall-off test would be a

feasible test method.

3. When oil is very heavy and comes up to surface either by natural flow or through

artificial lift, in most cases, the flow is intermittent. This is an adverse factor that limits

the measurement of flow rates and also affects the behavior of the bottomhole pressure

(BHP). These phenomena affect the reliability of the reservoir evaluation.

4. Some well producers in Mexico have static-pressure values that are so low that they do

not allow natural flow, or the differential pressure is so low that it stops production due to

high viscosity, frictional-pressure loss, formation damage, or low permeability. When this

situation occurs, it can prevent fluid from reaching surface, or the flow will be

intermittent.

5. In cases where the rig has a limited footprint that does not permit installation of surface

equipment for injection of diluents with coiled tubing, surface heaters, and other

equipment required to do a well test in terms of a

conventional drawdown/buildup process.

6. In cases where the hydrocarbon is already known and the

objective of the well test is to characterize the dynamic and

static properties of the reservoir.

7. Wells in which a stimulation job is planned or with high

volumes of fluids that would have the same function as the

injection fluid in a fall-off test, and when there is a DST

tool string used. After the stimulation job, a downhole shut-

in should be performed to record the BHP behavior.

Drill Collar 4 3/4" 43.5 lbs/ft

Crossover

CONTROL VALVE

"SELECT TESTER" VALVE

GAUGE CARRIER with 2 pressure electronic gauge

GAUGE CARRIER with 2 pressure electronic gauge

BIG JOHN JAR

SAFETY JOINT

MECHANICAL CHAMP-IV PACKER Casing 9 5/8", 53.5 #/ft, ΔP=10,000 psi

Crossover

3 1/2" Tubing

Radioactive tool

3 1/2" Tubing

Crossover

Circulation Sub

Crossover

3 1/2" Tubing

Crossover

Mechanical Firing Head

Safety Space Bar

Top of Perforating

TCP Guns 3 3/8", 20 c/m. F-60° HMX

Bottom of Perforating

Hydraulic Firing Head TDF

Figure 5 – Tool string


Tool-String Description Figure 5 shows a typical DST tool string that is used for performing the fall-off test.

The tester valve allows the downhole shut-in to be performed and is situated above the

gauges (pressure and temperature recorders). The tool string in Figure 5 shows the TCP guns that

enable perforation and evaluation of the formation with the same string in only one trip,

ultimately reducing rig costs for an operator by reducing operation time. Activation of the TCP

guns can be performed by applying tubing pressure or by dropping a bar. The retrievable packer

setting is mechanical.

Operational Sequence for an Injection/Fall-off Test Assessment with a DST Tool String In Heavy-Oil Reservoirs

The operational sequence is described below:

1. Run in the hole and set the packer

2. Pump the injection fluid with a constant injection rate

3. Perform operations for the downhole shut-in

4. Record the pressure response during the “fall-off”

5. Open the tester valve and recover the tool string

6. Recover the data from the gauges

7. Process, analyze, and interpret the information.

When running the TCP guns in the tool string, and the tool string reaches bottom, perform

the correlation and depth adjustment in order to situate the tool string at final depth.

As with any tool string that has possible leakage points (such as pipe joints, packer,

bottomhole valves, ball hanger, surface equipment, etc.), perform the respective tests in order to

ensure that all data recorded on gauges are representative of the reservoir.

It is extremely important to have an injection pump that allows a constant injection rate; this

consideration is one of the primary requirements for this type of test. The injection rate as well as

the injection pressure should be less than the fracture pressure of the formation. During the

injection period, exceeding the fracture pressure can result in communication with another

formation that could contain water or could generate mechanical damage in the well. However,

in some cases, the objective of the injection period is to create a hydraulic fracture, and the main

purpose of the fall-off test is to evaluate the fracture length and fracture conductivity. It is


important to monitor the tubing pressure and the casing pressure at surface during the fall-off

tests in order to ensure that all data recorded are representative of the reservoir being tested.

Fluid Selection for the Injection Test In cases in which it will be necessary to have a kill weight mud in the well that is different from

the injection fluid, the kill weight mud should be removed before the injection test is conducted

for safety reasons.To remove the kill weight mud, one option would be to use a circulating valve

in the tool string, which would enable displacement of the kill weight mud for the injection fluid

in order to avoid higher skins or emulsions in the reservoir.

In most assessments in heavy oil reservoirs, fluids injected and kill fluids were diesel, and the

formation damage after the injection was negligible, indicating that the compatibility of the

formation and heavy oil with the diesel did not create any reaction. Water is the least expensive

fluid available for use as injection fluid, but this is not recommended due to the possible

generation of emulsions that could cause problems during the test and cause formation damage

that could require expensive treatments to remove the damage. It is always advisable to have a

representative sample of the oil which is to be produced from the well; this reservoir fluid should

be tested in order to obtain the most appropriate fluid to use in the injection test; in some cases,

the stimulation fluids could perform a dual function such as eliminating the potential damage

created during the drilling and completion operations, and also, could be used as the fluid to

sweep the oil in the reservoir to create the pressure disturbance during the fall-off test.

History Case 1 This case concerns evaluation of a

reservoir in which oil gravity was

12ºAPI with an equivalent density of

1.39 psi/m in upper Cretaceous; the

BHT was 130ºC and the BHP was

4483 psi (3576 m TVD), calculating

an equivalent pore gradient of 1.25

psi/m. The analysis of the formation

damage, permeability, loss of friction 0

2000

4000

6000

8000

140 150 160 170 180 190 200 210 220140 150 160 170 180 190 200 210 220 230 240 250

Pressure [psia] vs Time [hr]

Running in the Hole

Detonating Guns

Running Out the hole

Gauge #7751 TP @ 3701.13 MPressure to

activate firing head

Injectingat 3 bpm Fall-Off

Controlof well

Well OpenedObservation period

Pressure testinto tubing

Figure 6 – History plot 1, History Case 1


pressure, the decrease in temperature when moving to the surface, and the increase of the

viscosity indicated that it would not be possible to perform an evaluation in terms of production,

unless some artificial lift method was used. For this reason, the operator decided to use an

injection test. Figure 6 shows the history plot recorded by the memory gauges.

The entire history recorded in the memory gauges during the test is shown in Figure 6. This

plot includes the running in the hole, activation of TCP guns, an observation period, injection

period, downhole shut-in, well kill operations, and operation to recover the tool string. The total

test time was slightly less than 6 days, which indicates that the evaluation time with a fall-off test

is very short compared with reservoir evaluation using an ESP test that usually requires more

than 10 days. Figure 7 shows the detail of pressure during the injection period and the downhole

shut-in.

Figure 7 - Fall-Off Test, History Case 1.

Memory gauges recorded 8

hours of data for the injection

period. The injection fluid was

diesel, and the injection rate

was 3 bbl/min. After the

injection period, the fall-off

Periodos de Evaluación

4200

4300

4400

4500

4600

4700

4800

4900

5000

Pres

sure

[psi

a]

185 195 205 215 225 235


4200

4300

4400

4500

4600

4700

4800

4900

5000

4200

4300

4400

4500

4600

4700

4800

4900

5000

Pres

sure

[psi

a]

185 195 205 215

Pres

sure

[psi

a]

185 195 205 215 225 235


Injectingto 3 bpm

Fall- Off

Start Shut-inperiod

4809 psi

4300.44 psi

1E-3 0.01 0.1 1 101

10

100

Log-Log plot: dp and dp' [psi] vs dt [hr]

Near Zone Behavior(Injecting Fluid)

Near Zone Behavior(Injecting Fluid)

Possible Bi-lineal Flow Period

Possible Bi-lineal Flow Period

Far Zone Behavior(Reservoir Fluid)

Far Zone Behavior(Reservoir Fluid)

Figure 8 – Log-log plot during the Fall-Off Test


test commenced with a downhole shut-in of 2 days.

Figure 8 shows the response of the derivative during the fall-off.

Figure 9 shows the numerical model adjustment in the log-log plot that considers a boundary

effect near the well. Applying the semilog “Horner method,” the parameters shown in Table 1

were obtained.

History Case 2 This case history concerns the assessment of a reservoir with an oil gravity of 12 ºAPI. The BHT

was 105º C, and the BHP in static conditions was measured as 2904 psi at 4482m TVD,

calculating an equivalent pore gradient of 0.65 psi/m. The analytical results showed that the

static pressure was abnormally low. These adverse conditions indicated that it would be

impossible to make the reservoir evaluation in terms of production.

Figure 10 shows the complete history of the data recorded in the memory gauges during the

test; this plot includes running in the hole, an observation period, and two injection periods due

to operative reasons that hindered initiation of the fall-off period after the first injection period.

However, the dynamic conditions were re-established (second injection period), and the

downhole shut-in period was initiated.

-1000 -800 -600 -400 -200 0 200 400 600 800 1000

-600

-400

-200

0

200

400

Tested w ell

Length [ft] vs Length [ft]

Border Effect (geological event) proximity wellboreBorder Effect (geological event) proximity wellboreWellWell

RADIAL HOMOGENEOUS WITH BORDER EFFECT RESERVOIR MODEL RESULTS

DATE (dd/mm/aa) 01-Abr-08

FALL-OFF START TIME TIME (hh:mm:ss) 05:24:21

FALL OFF DURATION (hrs) 48.18

GAUGE DEPTH (m) 3701.13

DEPTH (NMDD) (m) 3875

GAUGE (psia) 4299.62

GRADIENT (psi/m) 1.14EXTRAPOLATE PRESSURE

NMDD (psia) 4483

PERMEABILITY (K) (mD) 2890

FLOW CAPACITY (Kh) (mD*ft) 379000

TOTAL SKIN 29.7

ΔP SKIN (psi) 398.95

BORDER DISTANCE

BORDER (m) 45*NMDD, at the middle of the perforated interval

Table 1 ‐ Results of assessment for Case History 1.

Figure 9 ─ Numerical model adjustment in the log-log plot


In this case, the evaluated interval had already been perforated, and for that reason, it was

not necessary to carry the TCP guns in the tool string. The total cumulative injection time was 8

hours with a downhole shut-in of 53 hours. The total assessment time was 4.3 days considering

the running in the hole, well kill operations, and the recovery of the tool string.

Figure 10 – History plot, History Case 2.

Figure 11 shows the second injection period and the downhole shut-in.

Figure 11 — Fall-Off Test, History Case 2

1000

2000

3000

4000

5000

6000

7000

Pres

sure

[psi

a]

5/23/2008 5/24/2008 5/25/2008 5/26/2008 5/27/2008

Pressure [psia] vs Time [ToD]

Set Packer

Diesel Injecting Periods

2852.3 psi (200.5 kg/cm2)

Running outthe Hole

Bottom Hole Shuti-in (fall-Off Test)53.3 hrs

5016.6 psi (352.7 kg/cm2)

1000

2000

3000

4000

5000

6000

Pres

sure

[psi

a]

5/25/2008 5/26/2008

Pressure [psia] vs Time [ToD]

Diesel Injecting Period (Rate=3bpm)5016 psi (352.7 kg/cm2)

Bottom Hole Shut-in (Fall-Off Test)53.3 hrs

2024 psi(142.3 kg/cm2)


The injection rate was 3 bbl/min, the total volume injected into the formation was 1450 lbm of

diesel. At the end of the injection period, the downhole shut-in began (fall-off test). This

operation took 2.2 days as shown in Figure 11.

Figure 12 shows the response of the derivative during the fall-off. It also shows the behavior

of the derivative curve, which shows a radial composite reservoir that indicates the existence of

Figure 12 ─ Log-log plot, History Case 2.

an area near the well that represents the zone with the injected fluid, the transition zone (increase

in the values of the derivative curve), and finally, the response of the radial flow in the remote

area that is the zone with the heavy oil.

At the end of the wellbore storage, the slope of the derivative curve is -1/2 (spherical flow)

indicating a limited entry well model; this model assumes that the well produces from a

perforated interval smaller than the drained interval. In any model where there is a vertical

contribution to flow, there must also be a pressure drop in the vertical direction; thus, the total

skin obtained from the semilog plot

“Horner method” is composed of two

elements; i.e., the formation damage

and the geometrical damage. The

separations between the derivative and

“dp” curves indicate the existence of

high damage. In the remote zone in

which pseudo-radial flow was

1E-4 1E-3 0.01 0.1 1 1010

100

1000

Log-Log plot: dp and dp' [psi] vs dt [hr]

Near Zone Response(Injecting Fluid)

Near Zone Response(Injecting Fluid)

Possible Spherical Flow Period

Possible Spherical Flow Period

Far Zone Response(Reservoir Fluid)

Far Zone Response(Reservoir Fluid)

-3.6 -3.2 -2.8 -2.4 -2 -1.6 -1.2 -0.8 -0.4 0

3000

4000

5000

Semi-Log plot: p [psia] vs Superposition time

High Formation Skin exist in the wellbore

High Formation Skin exist in the wellbore

Figure 13 — History Case 2 Semilog plot‐diesel zone.


reached, the semilog method was applied in order to obtain the effective oil permeability and the

static pressure of the reservoir. The model fit is very good, which allows us to ensure that all the

parameters obtained are representative of the reservoir.

Figures 13 and 14 show the results of the calculation. It is important to state that the

calculation of the total damage was made in the area near the well. Also, the reservoir

parameters were obtained in the remote zone.

Figure 14 - Semilog plot-oil zone, History Case 2

The results obtained in this test were:

-3.6 -3.2 -2.8 -2.4 -2 -1.6 -1.2 -0.8 -0.4 0

3000

4000

5000

Semi-Log plot: p [psia] vs Superposition time

RADIAL COMPOSITE WITH PARTIAL PENETRATION EFFECT RESERVOIR

MODEL RESULTS DATE (dd/mm/aa) 24-May-08

FALL-OFF START PRESSURE TIME (hh:mm:ss) 16:38:55

FALL-OFF DURATION (hrs) 53.29

PRESSURE GAUGE DEPTH (mD) 4562.97

DEPTH (NMDD) (mD) 4627.5

GAUGE (psia) 2837

GRADIENT (psi/m) 1.13

EXTRAPOLATED PRESSURE (P*)

NMDD (psia) 2904

PERMEABILITY (K) (md) 46.2

FLOE EFFECTIVE NET PAY (mV) 34

FLOW CAPACITY (Kh) (md*ft) 5150

SKIN 48.8

ΔP SKIN (psi) 1800.85

Table 2 – Assessment Results for History Case 2


Once the parameters in Table 2 were obtained, a productivity analysis (Figure 15) was

conducted in order to validate the reservoir parameters obtained from the fall-off test; it is

important to mention that this productivity fit was performed by simulating an ESP artificial lift.

Figure 15─Productivity Analysis, History Case 2

Conclusions

Injection fall-off tests are recommended in wells where it is not possible to have natural flow or

flow rates in stable conditions due to the high viscosity of heavy oil, low oil mobility, or low

reservoir pressure. The injection fall-off test offers a feasible alternative for obtaining

representative reservoir parameters.

The average evaluation time in the injection test in the two history cases was 6.6 days

including all the operations involved in the test. These operations included 1) running into the

hole, 2) the injection period, 3) the fall-off period (downhole well shut-in), 4) the well-kill

operations, and 5) the operations to recover the tool string.

These history cases have verified that injection fall-off tests can offer the operator a

significant reduction in rig costs as well as in operations and services that would be involved in

performing a production well test, which generally averages approximately 12 days.

Data recorded during the reservoir evaluation show good quality, representative, and reliable

reservoir data. The downhole shut-in through the tester valve is one factor that helps to improve

the quality of information obtained.

Outflow Inflow�Pres = 2904�S = 48.9 Inflow�Pres = 3500�S = 2.78

FLOW RATE (bbl/d)150010005000

FLO

WIN

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TM P

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sig)

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Inflow/Outflow Plot


During the assessment, production flow rate at surface is not required, and that reduces rig

cost, because is not necessary to store or burn fluids during the injection test. These case

histories show that this method can provide a cost-effective method for providing a productivity

analysis with high-quality data that can help the operator determine production potential for each

interval. This in turn, enables the customer to develop the best, most economical design for

managing the reservoirs and completing the well.

References 1. Earlougher, R. J.: “Advances in Well Test Analysis,” Second Printing. AIME (1977).

2. Matthews, C.S., Brons, F., and Hazebroek, P.: “A Method for Determination of Average

Pressure in a Bounded Reservoir,” Trans., AIME (1954).

3. Soliman, M.Y.: “Well Test Analysis,” Halliburton (2000).

4. Wendler, C. and Mansilla, C.: “Options and Special Considerations for Successful Deep-

Water Well Testing of Heavy- and Low-Pour-Point Oils – Case Histories,” SPE 86944

(Marzo, 2004).

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