Formation Multi-Tester (FMT) Principles, Theory, and Interpretation

Formation Multi-Tester (FMT) Principles, Theory, and Interpretation

01987 Western Atlas International

CONTENTS Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Operation of the FMT . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Calibrations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Strain Gauge . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Quartz Gauge . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Qualitative Indications from FMT Pretest. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Reservoir Fluid Properties . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Density or Specific Gravity . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Resistivity . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Viscosity . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Fluid SampleTest . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Variable Pressure Control (VPC). . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Segregated Samples . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Estimating Sampling Time. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Evaluating Recovered Fluid Samples . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . When Sample Recovery is Primary Native Formation Fluids . . . . . . . . . . . . . . . . . . . . . . . . Prediction of Water Cut . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Recovery of Small Volumes of Formation Fluid or No Formation Fluid. . . . . . . . . . . . . . . Technique for Various Size Recoveries . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Fluid Flow in Porous Media . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Darcy’s Law . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Pressure Drawdown - Permeability Estimate. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Pressure Buildup - Permeability Estimate . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Spherical Pressure Buildup - Permeability and Formation Pressure . . . . . . . . . . . . . . . . . . . Cylindrical Buildup - Permeability and Formation Pressure . . . . . . . . . . . . . . . . . . . . . . . . . Comparison of Permeability Estimates . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Bed Thickness Definition During Buildup. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Subsurface Pressure Regimes. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Hydrostatic Pressure . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Overburden Pressure . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Formation Pressure . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Applications of FMT Pressure Measurements. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Measured Depth vs. True Vertical Depth . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Pressure Regimes in Water-Bearing Reservoirs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Supercharging . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Selection of Test Intervals . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Pressure Gradients and Particular Pressure Regimes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Determination of Movable Formation Fluid Density in Zones with High Connate Water Resistivity . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Defining Gas/Liquid and Oil/Water Contacts . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Zone Isolation or Communication . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Determination of Oil/Water Contact Below Total Depth of the Borehole. . . . . . . . . . . . . . Reservoir and Zonal Depletion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Monitor Injection Program in In-Field Wells . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Fracture Detection . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Extremely Tight Formations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Grain Size Effects . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . FMT Pulse Testing . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . FMTREALITY . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . List of Symbols, Including Subscripts . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Bibliography . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Appendix A . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Permeability from Drawdown . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Permeability from Spherical Buildup . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Effective Bed Thickness Computation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Permeability from Cylindrical Buildup . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Time Estimate for Sampling . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

1 2 7 7 8 8 14 14 16 16 20 21 21 21 23 23 25 26 26 27 28 30 31 31 34 35 37 37 37 38 38 39 39 41 41 42 42 42 42 44 46 47 47 47 49 49 50 50 55 56 56 58 58 58 59 59

Formation Multi-Tester (FMT) Principles, Theory, and Interpretation INTRODUCTION

The Formation Multi-Tester (FMT) is a sophisticated system of wireline testing equipment designed to measure formation pressures at any number of depth locations per single trip into an uncased wellbore. These pretest pressure measurements also provide a means of confirming adequate packer seal and a quick qualitative estimate of formation permeability prior to making a decision regarding the opening of one or both of the fluid sample chambers. Run on a multi-conductor logging cable, the FMT can be accurately positioned at selected depths by reference to a sequentially recorded spontaneous potential (SP) or gamma ray (GR). Formation testing normally follows the recording and evaluation of openhole logs from which potential target intervals are identified. Wireline

test information provides a fast and economical method for identifying theproduction potential of the targeted reservoirs.

The FMT provides more detailed and reliable vertical pressure profiles than can be expected from drillstem tests (DST). The ability to acquire multiple pressure readings provides a much quicker and less expensive method for obtaining a reasonably accurate profile of vertical pressure gradients. FMT pressure measurements are acquired from specific depth intervals while DST gauges are commonly located in the test tool string above the interval tested. The nature of the fluid between the zone being tested and the DST gauge depth provides for some uncertainty.

Comparison of FMT pretest pressures and drillstem test pressures.

unique variablepressurecontrol (VPC) provides forimproved sampling by avoiding excessive differential pressure across the packer seal. An analysis of the

recovered fluids is provided to aid in prediction of reservoir production characteristics. The capability for multiple pretest pressure recordings has made the FMT the primary openhole system for measuring vertical pressure distribution in a wellbore.

A profile of several DST pressures through a common pressure regime may not always define an accurate gradient. In a similar environment, FMT pressure data often provides descriptive gradients for gas or fluid type. The data given in Fig. 1 exemplify such a case.

The numerous pressure readings have been used to establish the hydrostatic gradients of mud columns, fluid and gas gradients in reservoir rocks, and vertical permeability barriers. Comparisons of FMT gradients on adjacent wells have been found useful in describing the presence or absence of lateral communication. Information from the pressure measurements can be significant in association with lost returns during cementing operations. Selective perforating and selection of methods to best control acid or frac fluid placement can also be improved through the use of FMT data. The information derived from the FMT can therefore be used to optimize completion methods and maximize ultimate reservoir recovery.

FMT pressure data are recorded on film and presented in both analog and easy-to-read digital formats. The stationary recordings at individual depths are a plot of pressure vs. time. Direct digital readouts are observable on surface instrumentation during the test, allowing for quick decisions on whether or not to open the fluid sample chambers. Two sample chambers can be filled at the same depth and segregated, or the two chambers can be filled at two different depths per trip in the borehole. Several chamber sizes are available for sampling. A

1

The downhole tool system includes the control electronics, a hydraulic section, and the test sample chambers. A schematic diagram of the subsurface

OPERATION OF THE FMT

The FMT makes pressure measurements while the tool is stationary at selected depths in an uncased borehole. If the pretest pressures indicate a good packer seal to the formation and a relatively permeable zone, fluid samples may be recovered by opening a sample valve and allowing one of the two sample chambers to fill. Photographs of the FMT packer section are shown in Fig. 2.

assembly is shown in Fig. 3. The control electronics and hydraulics are located in the upper part of the tool string, with the packer seal section and pistons directly below. Sample chambers are attached to the lower end of the tool assembly. A number of different chamber sizes are currently available (e. g., 1 gallon, 4 liter, 10 liter, and 20 liter). Other unique sizes may be found, depending upon geographical location. Without sample chambers on the tool string, the packer section is located approximately 5.5 ft off bottom, or 9 ft if the Hewlett-Packard quartz gauge is run. With two chambers of 10-liter capacity each, the packer section is located approximately 31 ft off bottom (34.5 ft with the H-P gauge).

FIGURE 3 Schematic diagram of the subsurface assembly of FMT with Variable Pressure Control.

FIGURE 2 Three views of the FMT packer section.

2

Operation of the downhole equipment is controlled from thesurfacelogging unit. A film recording is made of each complete cycle of operation. Recorded measurements are in time (seconds) rather than depth as the tool is stationary (see Fig. 4). The time grids or time lines are comparable to the depth grid on traditional log recordings with each line representing two seconds (rather than two feet) when English depth measurements are used. Pressures are recorded as an analog trace in Track I, providing a quick-look profile of packoff effectiveness and

permeability indication. Tracks II and III are divided into half-track digital scales of pressure (1000’s, 100’s, 10’s, units), providing for a more accurate reading of the recorded pressures. Hydraulic pressure may also be presented in Track I (dashed trace) to help identify the various stages in the tool’s set and retract cycles. Pressure listings are also available. Temperature may also be presented in Track I when the series 1966 electronics is run.

STATION DEPTH - XX840 HYDROSTATIC PRESSURE - 4546 psi

PUMP PRESSURE .--------------I 3001

FORMATION PRESSURE - 3978 Dsi

RECORDED DIGITAL SAMPLING PRESSURE (psi) ANALOG (psi)

SET ,PACKER

HYDR( ‘ATIC PRES su‘RE

I---.\ \ 1

I

....... ....... ....... ....... ....... .......

t0

t = 8 set IO set

............... ............... ............... ................. ................. ................. ................. ................. ................. ................. ................. ................. .................... .................... .................... .................... .................... .................... .................... ....................

...............

HYDROtTATlC PRES+lRE

FIGURE 4 Example of pretest pressure recording.

from entering the tool. The sleeve is easily removed at the surface for cleaning between runs.

At each designated test depth, operational practice includes both a before and after recording of hydrostatic mud pressure, i. e., before actuating and after retracting the hydraulic packoff section (see Fig. 4). The FMT has an internal motor, pump, and hydraulic system which are used in actuating and retracting of the packoff section. Hydraulically activated setting pistons cause a rubber donut-shaped packer element to press tightly against the borehole wall. A special nitrile rubber, which is sulphur cured, with peroxide-cured o-rings, is available for use in H2S environments. Hydraulic pressure is recorded at the surface, indicating proper (or improper) setting of the tool. The tool mandrel is held away from the borehole wall to reduce the possibility of differential sticking.

PRESSURE TRANSDUCER

PRETEST PISTON

A snorkel tube is then forced into, or pressed tightly against, the formation. This is followed by the movement of a small piston, called the pretest piston, allowing 10 cm3 of formation fluid to enter the pretest chamber at a more or less constant flow rate. The effect of this volume extraction on the formation pressure is observed and recorded at the surface (see Fig. 4). A 5-cm3 plug is available for use in wells where extremely tight formations are expected.

u EQUALIZING VALVE

I

J

--L WELLBORE

SAMPLE VALVES

SAMPLE TANK#l

At this point the logging engineer must be patient and allow the pressure to build up adequately to formation shut-in pressure (see Fig. 4). It is essential that shut-in pressure be recorded as long after the flowing portion of the pretest as possible in order to allow the buildup to approach actual formation pressure. If the pressure test is terminated too early, the shut-in pressure reading will be too low since sufficient buildup did not occur. Early termination of the pretest will also prevent later use of spherical and/or cylindrical model analysis. Pretest shut-in pressure is often referred to as initial shutin pressure. The tool is then (1) retracted prior to moving the tool, or (2) a sample valve is opened to allow formation fluid to flow into a sample chamber. In either of these cases the tool is ultimately retracted, at which time an equalizing valve is opened and the pretest fluid is expelled from the tool. A system schematic is shown in Fig. 5.

p SAMPLE TANK#2

FIGURE 5 Schematic of FMT system.

Operation of the pretest piston and the concurrent measurement of pressure are the keystones to determination of formation pressure and inferences of permeability. Formation fluid enters the tool through the probe during the pretest. As the probe is pressed against the face of the formation (it may even penetrate softer, unconsolidated rock) it also defines the area of flow from the formation as well as eliminating lateral mud cake entry into the tool. A schematic of the probe in both the retract and set position is given in Fig. 6. A sleeve, inserted in the probe, is slotted to function as a filter. The slits are 0.015 in. wide to prevent any debris larger than the slits

FIGURE 6 Schematic of the FMT probe in both the retract (upper) and set (lower) positions.

4

If the pretest data indicates adequate conditions for fluid sampling of the formation, a sample valve may be opened. As many as two fluid samples may be recovered per descent into the wellbore. These samples may be taken at the same depth or at different depths. If both sample chambers are filled at the same set depth, they will be segregated from one another.

SECTION OF LOG REMOVED

Atlas Wireline Services has developed a unique Variable Pressure Control (VPC) system for use with the FMT

The VPC is a variable orifice valve located upstream from the sample tank valve. Both valves are closed when no sample is being taken. To obtain a sample, the tank valve is opened first, followed by the variable orifice valve. The variable orifice valve is controlled from the surface and is opened only until a suitable flowing pressure is attained. The VPC avoids excessive pressure differentials and samples are obtained successfully without guesswork. This feature also prevents formation plugging in unconsolidated sands. The logging engineer can adjust the VPC to pressure increments as small as 5 to 10 psi. Samples can be obtained without damage or plugging from formation collapse. In addition, samples can also be taken above bubble point pressure, thereby eliminating non-representative gas/oil ratios caused by the effects of relative permeability. Testing at multiple flow rates and multiple drawdown pressures may be useful in evaluating formation mechanical properties relating to sand control and consolidation. An analog pressure record showing VPC sampling at three different flow rates is shown in Fig. 7. Segregated sampling at the same set depth usually involves filling the larger sample chamber first, the idea being to drain the flushed zone (mud filtrate) as much as possible. The second sample chamber is then ideally filled with representative reservoir fluids.

I -----me

-i

Analog pressure record showing VPC sampling at three different flow rates.

The tank valves in the VPC-FMT system can be opened and closed as often as required. This feature allows the logging engineer to check for plugging and enables him to reuse the first sample tank in the event of an early packoff failure during segregated fluid sampling.

face of the formation. As with a standard pretest, hydrostatic pressure is again recorded to provide a verification of transducer stability, repeatability, and reliability. Hydrostatic pressures recorded before and after tool setting should read within +l psi of one another (assuming no change in the mud column) (see Fig. 8).

After a sample chamber is filled, the sample valve is closed by a spring and kept closed because of the balanced seal design, thereby sealing the fluid in the sample chamber at formation pressure. The pressure transducer transmits the final shut-in pressure to the surface where it is recorded. A film record of the pretest and sampling steps is illustrated in Fig. 8.

After the FMT tool and sealed samples are returned to the surface, apressureregulator, separator, andgasmeter are used to extract the samples individually. Recovered gas is bled from the sample chamber through the separator and measured by the gas meter (in ft3 at surface conditions). Water and oil are drawn off in the separator and then poured into a calibrated vessel where their volumes are measured in cm3. When H,S is suspected in the sample, the gas is bubbled through an

After completion of the sampling, the hydraulic system pressure is released and hydraulic pressure reversed in order to retract the packer and backup shoes from the 5

ANALOG

RECORDED DIGITAL SAMPLING PRESSURE (PSI)

(PW

~ I~i’-i~~~ :i_ : : : FIGURE 8. Film record of pretest and sampling steps.

6

H,S scavenging bottle to remove the H,S. The remaining gas is vented into the atmosphere. Recovered water is routinely tested for chloride concentration and any recovered oil is measured in terms of ‘API gravity. An example of a sample evaluation is shown in Fig. 9. Further analysis, if needed, can be made in the laboratory.

logging tools in that they provide a basis for correcting strain gauge measurements for temperature effects encountered in the borehole environment. A high-quality deadweight tester is used. A calibration test strip is shown in Fig. 10.

If an undisturbed sample is required for laboratory analysis, a breakoff tank can be utilized. The breakoff tank is a 4-liter capacity high-pressure tank which can be detached from the FMT at the surface without bleeding off any pressure or fluids. The breakoff tank meets U. S. Department of Transportation safety standards for transport by any common carrier. CALIBRATIONS Strain Gauge The routine shop calibration of FMT strain gauges is essential to obtaining accurate pressure measurements in the borehole environment. These routine checks should be performed within a 30-day period and are analogous to shop calibrations performed on other

FIGURE 10 Calibration test strip for the FMT strain gauge.

FORMATION TESTER RECOVERY & INTERPRETATION DATA TEST NUMBER 3

Depth

2588.0

-0RMATION and MUD DATA

Test Type: 0 Open Hole 0 Cased Hole

Formation Porosity

TOOL DATA

Rt

% Source

RW

Tool Type Probe Type Sample Unit Size Flow Control Tool Number

PRESSURE DATA Initial Shut in Build Up Time Sampling Range Sampling Time Final Shut in Final Shut in Time Hydrostatic Surface Chamber

1965 DUAL PASSAGE 3550 OPEN 71577

24170 0.1 400 - 10000 3.75 24110 6 29510 7067

“C “C

zi

Source of Rw cm3

ppm; Cl (Titrated)

NaCl (Chart) Water Saturation 1.55

Rmf

Source of Rmf NaCl (Chart)

kPa min kPa min kPa min kPa kPa

RECOVERY INFORMATION 0.0127 Gas Distillate 200 Oil GOR 2950 W ater NaCl (Chart) Mud Formation Water

ii?

PPn 20

“C

ppm; Cl (Titrated)

wn

ms cm3 APl/15.5”( cm3~APl/15.5”( Cm3; Res ppm; Cl (Titrated) cm3; Sand %

0.18

18

0~ wm

cc

May be Expected At This Depth.

INTERPRETATION Remarks

SWAN HILLS

2nd TANK OF SEGREGATED SAMPLE

FIGURE 9 Typical sample evaluation.

7

The Atlas FMT is electrically calibrated prior to being lowered into the well. The wellsite calibration method uses deadweight tester data and temperature corrections determined in the laboratory on the strain gauge pressure recordings. The calibration process is repeated on each survey to ensure that proper response is maintained. The wellsite calibrations also verify the reestablishment of the shop calibration response.

errors of 100 psia for standard H-P gauges. Selected Atlas modified H-P gauges will have a maximum error of 20 psia under the same conditions and will read within ?5 psia within 2 minutes of the temperature change. The accuracy will be within +2 psia when the rate of temperature change is less than 0.5 OF per minute. QUALITATIVE INDICATIONS FROM FMT PRETEST

Quartz Gauge

The Hewlett-Packard quartz gauges are accurately calibrated by the manufacturer. These gauges are more accurate than the deadweight testers used to field calibrate strain gauges, therefore a field calibration is not required. However, it is important that periodic shop comparisons with a deadweight checker be made to ensure/verify stable quartz response with time. Quartz gauges do require significant temperature correction and Atlas’ H-P probes are modified to measure the temperature of the most temperature-sensitive component in this gauge. High-precision quartz gauges are typically used when studies of formation pressures require the utmost accuracy These gauges typically have an accuracy as

follows. l

l

l

If temperature is known to l°C accuracy, f 0.025% of pressure reading. If temperature is known to 10°C accuracy, + 0.1% of pressure reading. If temperature is known to 20°C accuracy, + 0.25% of pressure reading.

The temperature is accurate within + 5’F (+ 3OC). Quartz gauges also provide good repeatability (+ 0.5 psia) and a large amount of pressure data. Their single limitation is the time factor necessary for stabilization before measuring true pressure, i. e., several minutes may be required before reaching stabilization. It is also necessary to depth-correct pressures read from the quartz gauge to a pressure reference level due to the fact that the quartz gauge is physically located lower than the strain gauge on the tool string. The quartz gauge consists of two crystal oscillators, both being sensitive to temperature and pressure. However, one crystal performs as a sensor of fluid pressure and temperature while the other crystal is used as a reference to provide frequencies suitable for transmitting on wirelines. They are calibrated as a pair and both must have the same temperature for equilibrium pressure. Temperature changes of a few OF per minute can cause

The curve character of the pretest analog recording of pressures is affected by the pretest and sampling sequences. A schematic illustrating flow during pretest is shown in Fig. 11A. The analog pressure recording for a typical test is shown in Fig. 11B. The setting of the tool begins on the left of both figures with time increasing to the right. At the left of Fig. llB, hydrostatic pressure is recorded but when the equalizing valve is closed, the rubber packer engages and is pressed against the mud cake. A hydraulic seal is likely to occur before the packer and mud cake are fully compressed, therefore the pressure in the tool flow line is often observed to momentarily build up slightly above hydrostatic pressure. The pretest piston is then drawn back, allowing 10 cm3 of formation fluid to enter the pretest chamber at a constant rate as shown in Fig. 11A. The end of the flowing or drawdown phase is indicated at time tl in Figs. 11A and 11B. As the piston motion ceases, flow stops and the pressure builds up to formation pressure as shown on the right side of Fig. 11B. When the tool is retracted, the drawdown piston is reset thereby purging the pretest fluid into the wellbore, and the equalizer valve is opened allowing the pressure to return to hydrostatic. The difference between flowing (drawdown) pressure and shut-in pressure is AP and the time necessary for flow to stop from the beginning of the drawdown is referred to as At. Both AP and At are illustrated in Fig. 11B. These values of AP and At are used to determine permeability from the drawdown. A pressure record of the FMT internal hydraulic system during the pretest sequence is illustrated in Fig. 11C. The steps indicated are (1) the closing of the equalizing valve, (2) the packer engagement, (3) the pretest piston movement, and (4) the completion of the pretest piston movement. This internal pressure record is important for monitoring tool performance and is usually recorded as a dashed trace in Track I (see Fig. 4). Furthermore, this measurement is not used directly in the evaluation of formation pressure data. During pretest, flow, shut in, and the stopping of the pretest piston will coincide only if formation permeability is adequate to allow the formation fluids to flow fast enough to fill the volume created during the move-

Aq

PRETEST DISPLACEMENT

PRETEST FLOW RATE ’ (HIGH PERMEABILITY) A

A

HYDROSTATlC PRESSURE -

PRETEST PRESSURE

P

HYOROSTATlC PRESSURE

SHUT IN FORMATION PRESSURE

LW-

(P

PRETEST PRESSURE SHUT IN FORMATlON PRESSURE

B - At ‘1

f

INTERNAL HYDFjAULlC PRESSURE INTERNALHYDRAULICPRESSURE C

EQUALIZING

VALVE CLOSURE

FIGURE 11 Schematic illustration of flow during pretest.

FIGURE 12 Typical analog pressure record in a low permeability formation.

ment of the pretest piston. If formation permeability is too low, the pretest piston will cause the pressure to drop below the bubble point and multiphase flow may occur at the tool/formation interface. Although the piston has completed its stroke, the formation will continue to trickle fluid into the tool until 10 cm3 has flowed. A typical analog pressure record under these conditions is illustrated in Fig. 12A, B, and C. Observed pressures will eventually build up to formation pressure if sufficient time is allowed. An example of a long duration pretest is shown in Fig. 13.

in extreme cases prevent 10 cm3 being drawn into the tool. In Fig. 15A, light plugging is indicated by a rough, irregular response during the drawdown or flowing period. Severe plugging, if it occurs immediately upon drawdown, is virtually indistinguishable from a tight test (compare Figs. 15B and 14E). The presence of gas in the flowline causes the abrupt changes in pressure to occur more gradually due to gas compression and expansion as shown in Fig. 16A. If the packer is set on a tight formation, the effect of pretest is to expand the gas in the flowline by 10 cm3 and reduce its pressure to some nonzero constant value as shown in Fig. 16B. In either case, gas may be eliminated from the flowline by opening the sample chamber when set against a tight formation. This procedure in effect allows the gas to distribute itself over the small flowline and much larger sample volume, thereby allowing it to be captured in the sample jug (this procedure cannot be done with all tools without wasting the sample test).

The effects of formation permeability in the vicinity of the FMT probe on the pretest pressure record are illustrated in Figs. 14A, B, C, D and E. These comprise a family of typical FMT pretest pressure analog records for permeabilities varying in order of magnitude increments from 100 md to 0.1 md to tight. Note that the flowing time increases between 10 md and 1 md, indicating that the formation permeability is sufficiently low so that it cannot flow fast enough to fill the volume displaced by the pretest piston. The illustrations in Fig. 14 are intended only as guidelines since the actual permeability depends on the drawdown from formation pressure, flow rate, and nature of fluid.

Seal failure is caused by the inability of the rubber packer to isolate the probe flow channel from the mud column and may occur at any time during the pretest sequence. Figure 17A illustrates a catastrophic seal failure such as might occur in a washout or highly rugose hole. The pretest pressure record remains at hydrostatic even though the pretest piston goes through its cycle. In Fig. 17B, a relatively low permeability is indicated; however, upon closer inspection the final formation pressure and

Other factors often affect the character and quality of the pretest pressure record. Debris drawn into the drawdown line during pretest may cause plugging and 9

RECORDED DIGITAL SAMPLING PRESSURE

FIGURE 13 A long duration pretest.

10

APPROXIMATE

I

PERMEABILITY

1 RECORD C

FIGURE 14 Family of typical analog pretest pressure records for different permeability ranges.

FIGURE 15 Analog pretest pressure recordings for (A) irregular light plugging and (B) severe plugging.

11

FIGURE 16 Examples of (A) gas compression/expansion in the flowline and (B) tight gas zone, where gas expands to 10 cm3 in the flowline.

I I 1

I B

FIGURE 17 Example of (A) catastrophic seal failure and (B) case where apparent formation shut in pressure is suspiciously similar to hydrostatic pressure.

12

right of the depth track as shown in Fig. 18. The recorder steps the pressure data in digital increments of 1000, 100, 10 and 1 psi from the track nearest the depth track and then to the right. For example, at time 80 sec. in Fig. 18, the digital record indicates a formation pressure of 3927 psi and still building up slightly. It is apparent that resolution in this case is 1 psi. This example is an FMT measurement with the strain gauge. The HewlettPackard gauge is designed to improve the resolution to 0.1 psi and the 1000 must be read from the analog (Track I) data with 100, 10, 1, and 0.1 values read from the digital track. All pressure data (temperature corrected and uncorrected) is recorded on magnetic tape and may be retained for later processing.

initial hydrostatic pressure are nearly identical. These situations should be viewed very carefully since either a seal failure has occurred or virtually no overbalance exists with respect to the formation. The latter situation may indicate the need to weight up the mud as the well may be near blowout conditions. Measurements of these types should be repeated to determine which situation exists so that appropriate action can be taken. The FMT presentation includes both analog recordings of the pretest pressure record and the internal FMT hydraulic pressure. Both are recorded in the left-hand track (see Fig. 18). Where greater accuracy and resolution are required, four digital tracks are placed to the

- - - - - - -PUMP - - - - -PRESSURE ---- ------ -

RECORDED DIGITAL SAMPLING PRESSURE (Psi)

ANALOG

............... ..... .......... ................. ................. ................. ................. ................. ................. .................... .................... .................... .................... .................... .................... .................... .................... .................... .................... .................... .................... .................... .................... .................... .................... .................... .................... .................... .................... .................. . .................... .................... .................... .................... .................... .................... .................... .................... ..... ....... ........

............... ............... ...............

FIGURE 18 Analog pressures allow a quick qualitative reference. The digital pressure record provides greater accuracy and resolution for quantification of pressure data.

13

increasing temperature but increases with higher total solid concentration and pressure. The effect of pressure on the density of water is comparatively little, as can be seen on the chart in Fig. 19 which can be used to determine the density of water. Alternatively, if density at a certain temperature and pressure is known, total dissolved solids or chlorinity (in ppm) can be read from the chart.

RESERVOIR FLUID PROPERTIES

In conjunction with quantitative well log evaluations, the fluid samples and pressure data obtained from the FMT can be used to estimate formation pressures, permeabilities, hydrocarbon production rates, and depths of oil/water, gas/oil, and gas/water contacts. The samples recovered also supply information on the type of formation fluids, gravity of oil, water cut, and gas/oil ratio. FMT data interpretation involves considerations of fluid pressure behavior and other physical properties of formation fluids such as density, resistivity, and viscosity. The pore space of reservoir rocks may contain water, oil, and gas as a single phase or in any combination of these fluids. It is imperative that these properties of reservoir fluids be known or reasonably approximated in order to reliably evaluate the production characteristics of the reservoir rocks.

Specific gravity of oil is related to its API gravity by the relation 141.5 Yo =

(1)

OAP1 + 131.5

where y0 is the specific gravity of oil at 60°F referred to that of water at 60’F. When dissolved gas is present in oil, the specific gravity of the latter depends upon the gas/oil ratio, decreasing as the gas/oil ratio increases. Figure 20 can be used for determining reservoir density of oil in g/cm3 for a known value of GOR. Figure 21 shows the variation of specific gravity of oils with temperature while dry gas density, as a function of reservoir pressure and temperature, is illustrated in Fig. 22.

Density or Specific Gravity

Density of water depends upon its salt content, temperature, and pressure. The specific gravity of a substance is the ratio of its density to that of water at specified temperatures. Density of water decreases with

CDNSTRVCTED FROM DATA IN TABLES OF INTERNATIONAL CRlTlCAL VALUES AND LABORATORY DENSITY MEASUREMENTS

t

i

,

i

i

i

i

TdTAL DI’SSOLVED SOLIDS ;20 1 , ppm I IO’ 1 , ,,

I

,

240 I I

280 ,

,“A \,-t”.\rb”\l\,

1

160

H

t EXA

M

PLE

RESER~~IRT~MPERATUR~

= 175 OF

’

FIGURE 19 Chart for determination of water density.

14

I

30

1800

I

2000

40 OIL GRAVITY (OAPI)

FIGURE 20 Chart for determination of reservoir density of oil.

C,H, = Ethane C,H. = Propane Cal,,, = Butane IC.H.., = lsobutana

FIGURE 21 Gravity-temperature

relationship.

15

1600

I

50

60

and atmospheric pressure) to the viscosity of gassaturated oil for the known GOR at reservoir conditions.

Viscosity of natural gas depends upon its gravity with respect to air at standard conditions. Effects of temperature and pressure on the viscosity for natural gases, ranging in gravity from 0.6 to 1 .O, may be approximated by use of Fig. 27.

FIGURE 22 Density of dry gas vs. temperature and pressure.

Resistivity All porous rocks contain some water. By virtue of ionized salts contained in solution, these formation waters are electrically conductive but may exhibit resistivities ranging from 0.01 ohm-meter to several ohm-meters. The predominant salt in these solutions is sodium chloride. Resistivity of such an electrolyte decreases with increasing salt concentration (due to the higher concentration of ions, which carry electric charges) and higher temperature (which increases the mobility of those ions). Resistivity of formation water may be determined by direct resistivity measurement on a sample, chemical analysis, or an estimation of equivalent NaCl (in ppm) from well logs. The nomograph in Fig. 23 shows the resistivity of a brine solution as a function of temperature and equivalent NaCl concentration. Viscosity Viscosity of a fluid is a measure of its resistance to flow. The lower the viscosity of a fluid, the more readily it flows. Viscosity of water decreases with increasing temperature just like honey thins on warming. Water viscosity also depends upon salinity. These variations due to

temperature and salinity are shown graphically in Fig. 24. Changes in water viscosity are significant when determining permeability from drawdown. The effect of pressure on the viscosity of water is negligible. Viscosity of gas-free crude oil also decreases with temperature (Fig. 25). From a knowledge of crude oil ‘API gravity and formation temperature, the viscosity of gas-free crude oil can be determined (Beal, 1946). The amount of gas dissolved in oil has an important bearing on viscosity at reservoir conditions. Figure 26 is used to correct the viscosity of dead oil (at reservoir temperature

Nomograph for determination of resistivity or salinity of brine solutions.

16

011

I 150

I 100

I 200

I 250

I 300

I 350

I 400

d

RESERVOIR TEMPERATURE (“F)

FIGURE 24 Water viscosity vs. temperature and salinity (in ppm NaCl equivalent).

4000 - \ 2000 - \

600 j \ 400 -\ \ I\\ 2oo \\ \

\

100 -& 60: \' 40- \ 20 -

10 7

t \ \ 1

-5 \ \ t \

6: 42-

1.0 7

-

-

0.6 :: 0.4 0.2 -

Ju

0.1 ..ILL 10 CRUDE OIL GRAVITY OAP1 AT 60°F AND ATMOSPHERIC PRESSURE FIGURE 25 Viscosity of gas-free crude oils.

17

M SOLUTION GAS/OIL RATIO (ftalbbl)

VISCOSITY OF DEAD OIL (cP) (AT RESERVOIR TEMPERATURE AND ATMOSPHERIC PRESSURE)

FIGURE 26 Viscosity of gas-saturated crude oils.

18

0.050 -

0.040

0.040 -

0.030

0.030 -

c v

a^ 0

c i7 8 0.020

2 0.020 2

E \

I

\

I

5

0.015

0.010 0

100

300 200 TEMPERATURE (“F) la\ 1-1

400

500 TEMPERATURE (“F) fb)

0.050 I GRAVITY = 10 RICH GAS 0.040

iE‘ 0 c z 8 0.020 ” >

I

-

0.010 0

100

200 300 TEMPERATURE (“F)

400

500 TEMPERATURE (“F)

Cc)

Cd)

FIGURE 27 Charts for determining viscosity of natural gas.

19

FLUID SAMPLE TEST

The original purpose of wireline formation tests was to provide a means to obtain a sample of formation fluid and bring it to the surface. The multi-set pretest capa-

bility of the FMT has tremendously improved the ability to determineif an adequatepacker seal and sufficientlypermeable zone are present prior to opening a sampie chamber. The FMT is also capable of gathering two

samples per descent into the wellbore. Several different sizes (capacity) and combinations of sample chambers are available (see Table 1). With the FMT, the percentage of successful fluid recoveries has shown tremendous improvement and rig time has been reduced. The ability to acquire segregated samples from the same zone improves the chance of acquiring representative reservoir fluids. TABLE I

VARIABLE PRESSURE CONTROL FORMATION MULTI-TESTER (VPC-FMT) SPECIFICATIONS Length Without Sample Chambers (sample chambers lengthen the distance below the packer, e. g., two ten-liter tanks and H-P gauge would provide a distance of 34.5 ft)

18 ft 4 in. (w/o temp & H-P gauges) 19 ft 4 in. (wltemp & H-P gauges) Packer is set 5 ft 5 in. above the bottom of the tool w/o sample tanks; 9 ft w/H-P gauge

5.59 m (w/o temp & H-P gauges) 5.89 m (wltemp & H-P gauges) Packer is set 1.65 m above the bottom of the tool w/o sample tanks; 2.74 m w/H-P gauge

W eight, Overall Without W ater Cushion

982 lb

445 kg

Maximum Tool Diameter, Retracted

5.125 6.125 7.875 9.188

Maximum Hole Diameter

12.0 in., w/standard pad 16.0 in. or 20 in. available with extension kits

30.48 cm 40.64 cm or 50.8 cm available with extension kits

Maximum Pressure Rating

15,000 psi (20,000 w/specially equipped tool)

103,350 kPa (137,800 kPa w/specially equipped tool

Maximum Rating

350° F (425°F w/specially equipped tool)

177oc (218’C w/specially equipped tool)

Pretest Chamber Fluid Capacity

10 cm3 (5 cm3 plug is available)

10 cm3 (5 cm3 plug is available)

Sample Chambers, Fluid Capacities (water cushions are available)

1.06, 2.64, and 5.28 gal tanks are standard (other tank sizes are available in some specific geographical areas)

4, 10, and 20 liter tanks are standard (other tank sizes are available in some specific geographical areas)

+ 0.8%

* 0.8%

+0.13%

+0.13%

-+l.O psi

k6.89 kPa

kO.1 psi r0.4 psi (+ 1 .O psi + 0.1% of pressure reading)

f 0.6894 kPa k2.76 kPa (k6.89 kPa + 0.1% of pressure reading)

Temperature

Strain Gauge Accuracy Without templpressure correction With templpresssure correction Resolution Hewlett-Packard Quartz Gauge Accuracy with temperature correction Resolution Repeatability Accuracy at thermal equilibrium

in., in., in., in.,

w/slim hole pad w/standard pad w/16 in. extension kit w/20 in. extension kit

13 cm, w/slim hole pad 15.56 cm, w/standard pad 20 cm, w/16 in. extension kit 23.34 cm, w/20 in. extension kit

tanks can be filled at one set depth and segregated from one another. The premise is that the first tank will drain

In addition to identifying the production potential of targeted reservoirs, sampling is also an effective means of identifying fresh water aquifers. Drilling fluids are typically more saline than potable waters. The resistivity of the recovered fluid (Rrr), if some percentage of formation fluid is obtained, can provide the fingerprint defining such potential water supplies. Regulatory agencies are interested in identifying such aquifers so as to make assurances that the water-bearing zones are adequately isolated from any potential contamination. Segregated samples, taken at the same packer setting, often provide some uncontaminated formation water.

pretest pressure data allows for a quick approximation of the time required to fill a sample chamber. The longer

Sampling has also been used effectively to pinpoint gas/oil, gas/water, and oil/water contacts in highpermeability, high-porosity reservoirs.

the tool sets stationary and packed off to the formation, the greater becomes the risk of sticking the tool. For this reason it is significant to know how much time will be involved in filling a sample tank.

off most of the invaded filtrate from the flushed zone surrounding the packoff and the subsequent sample obtained in the second chamber will be more representative of native formation fluids. Estimating Sampling Time

Another advantage of the multi-set capability is that the

An estimate of the time period (in minutes) required to fill a one-gallon sample chamber can be made from the following:

Variable Pressure Control (VPC) Atlas Wireline Services’ unique Variable Pressure Control (VPC) allows for better sampling of unconsolidated formations where excessive drawdown or excessive flow rate might cause formation collapse, resulting in seal failure, toolplugging, or formation plugging. Earlier ver-

t = 63.1 (AP,,~)

(2)

qpt (AP,)

sions of FMT tools used a flow line restrictor or water cushion to combat the problem of excessive drawdowns and excessive flow rates. The flow line restrictor was placed in the flow line upstream from the sample chamber to limit excessive flow. Water cushions were used to accomplish the same effect by causing the fluid filling the sample tank to displace a piston which pushed water through an orifice into an air-filled chamber. The flow rate was controlled by installing an appropriate sized orifice prior to the job.

where: t

= time required to flow one gallon, in minutes

Appt = drawdown during pretest (P formation - Pflowing), psi

The VPC is located upstream from the sample tank valve and has a variable orifice. Both VPC and sample tank valves are closed when no samples are being taken. When a sample is desired, the tank valve is opened first followed by the opening of the variable orifice valve, which is controlled from the surface. Once opened, the variable orifice responds to pressure in the sample line by slightly opening or closing to maintain a constant pressure. Excessive packer differentials are avoided and samples can be successfully retrieved without guesswork.

APS

= drawdown during sampling (P formation - Pflowing), psi

qpt

= flow rate during pretest (chamber size/time to fill), cm3/sec

63.1 = conversion factor =

3785 cm3/gal 60 sec/min

Equation 2 is a simple extrapolation of flow during pretest vs. flow during sampling. When sampling is performed without a flow line restrictor or water cushion, the sampling flowing pressure is typically very low and

The VPC also permits sample retrieval from zones which are above bubble point pressure, eliminating npnrepresentative gas/oil ratios caused by the effects of relative permeability.

APS

= Pf

(3)

where pf = formation pressure.

Segregated Samples

The time estimate equation only approximates sampling time because other factors (e. g., relative permeability, flowing pressure, turbulence, debris, plugging, etc.) will influence the flow rate into the FMT. If samples

In tight, invaded formations it is often difficult to obtain a sample which is representative of formation fluids. The two-chamber capability of the FMT improves the chance of obtaining a representative sample since both

21

minigal. Following the pretest, a 2.56-gal (9700-cm3) sample was retrieved in 1.47 min for an actual flow rate of 0.57 min/gal.

larger than one gallon are to be retrieved, the time estimate derived from Eq. 2 is simply multiplied by the difference in chamber size (in gallons). For example, a 2.75gallon tank would take 2.75 times the value calculated in the equation.

If a VPC tool had been used and flowing pressure was adjusted to 2000 psi, the expected rate would be 4.61 min/gal and the retrieval of a 2.56gal sample would have taken 11.8 minutes. By using the VPC, sampling would have taken a few minutes longer but the danger of formation collapse, erroneous gas/oil ratio, and/or debris plugging of the flow lines would be lessened.

Example A log of a pretest followed by a sample test is given in Fig. 28. The flow rate (q) is determined to be 10 cm3/4 set, or 2.5 cm3/sec. The pressure drawdown during pretest is the difference between the shut-in and flowing pressures, which is indicated to be

The ability to predetermine a sampling time provides the responsibleperson at the surface with information which helps him to decide whether to chance sampling that particular zone or to move the tool and find a more permeable depth to sample. The time sampling estimate also helps thelogging engineer make a judgment on the proper VPC pressure setting to utilize.

ap*t = 2263 psi - 2215 psi = 48 psi

If the sample was recovered without a flow line restrictor or water cushion, the flow rate is estimated to be 0.54

.._--..-- 3 DIGITAL SAMPLING PRESSURE

FIGURE 28 Recording of pretest pressures followed by sample pressures.

EVALUATING RECOVERED FLUID SAMPLES

mud filtrate vs. formation water, per cent water cut, and gas solubility in water and/or oil

Fluids recovered in the sample tank are mud filtrate, native formation fluids, or a mixture of the two. Recovered mud filtrate is not representative of formation fluid. Recovered formation fluids are presumed to flow into the sample chamber in the same proportions of gas, oil, and water as they would in production of the zone.

l

Samples recovered may be substantially formation fluid, substantially mud filtrate, or any mixture in between. Several methods have been developed to evaluate these differing conditions.

The quantity of recovered fluid is a function of time, fluid viscosity, and pressure in addition to permeability. Quick chamber fillups occur in high permeability formations; however, sample chamber fillup can occur in tight formations if sufficient time is allowed. Therefore, the amount of fluid recovery is not diagnostic of permeability. Fluid recovery in excess of 1000 cm3 is sufficient to allow realistic estimates of: l

l

When Sample Recovery is Primary Native Formation Fluids When a relatively large fraction of the sample volume is native formation fluid, the empirical chart of Fig. 29 may be used to predict the production from the formation. This chart was developed for porosities greater than about 25 5’0 and shallow filtrate invasion. The volume of recovered gas at surface conditions (in ft3) and recovered oil (in cm3) is all that is required to utilize the chart. This chart was prepared for a one-gallon chamber, therefore all values of recovered volumes must be divided by the sample chamber size used (in gallons) to normalize the

Gas/fluid ratio, i. e., gas/oil ratio (GOR) and gas/water ratio (GWR) Production prediction, i. e., hydrocarbon vs. water,

I

GAS-OIL RATIO/ (ft3/bbl)

A

/

/

Viscosity of recovered fluids

/

WATER ZONE

OIL RECOVERY - cm’ PER GALLON SAMPLE CHAMBER SIZE

FIGURE 29 Empirical interpretation chart for l-gallon sample tank size and high-permeability formations.

23

Entering the above oil and gas recovery data on Fig. 29, the data point falls clearly in the oil zone. Hence, oil production is predicted with a gas/oil ratio of 410 ft3 per barrel of oil. In this case the formation shut-in pressure (SIP) is 2800 psi. Since the data point falls well above and to the right of the 2800 psi shut-in pressure (SIP) line, no water production is predicted with the oil. If the data point had fallen below the SIP curve, water production would have been predicted. An indication of water production should not necessarily condemn a zone since these empirical charts (Figs. 29 & 30) have a tendency to be pessimistic. Any use of these charts should always be supplemented with other information on the tested zone.

recovery to a volume-per-gallon basis. The chart given as Fig. 30 was prepared for a 2.75gallon chamber. These two charts were empirically derived from a large number of tests carried out by Shell Oil Company. The charts have been found to yield realistic estimates when the sum of recovered volumes (converted to subsurface temperature and pressure) is not appreciably less than the volume of the sample chamber. Example

The recovered fluids in a l0-liter (2.64-gallon) sample are 4.0 ft3 of gas at surface conditions and 1550 cm3 of oil and 8000 cm3 of water (both filtrate and formation water). The recovery data must first be normalized to a volume-per-gallon basis, so the recovery becomes

Gas/oil ratio anticipated in production may be estimated without the use of Fig. 29 by the following equation:

4.0

Gas Recovery = - = 1.52 ft3 per gallon 2.64

GOR =

1550 Oil Recovery = - = 587 cm3 per gallon

Gas Recovery (ft3) Oil Recovery (cm3)

x 159,000

(4)

The recovery used in Eq. 4 does not have to be normalized to a per-gallon basis. Measured values can be used directly regardless of sample tank size. This equation plots as the straight lines of gas/oil ratio (GOR) in Figs. 29 and 30.

2.64 8000

Water Recovery = - = 3030 cm3 per gallon 2.64

OIL RECOVERY (cm3) h

FIGURE 30 Empirical interpretation chart for 2%-gallon sample tank size and high-permeability formations.

24

Prediction of Water Cut ff,(~O>

x 100

ffw

=

Rrf

= resistivity of recovered fluid

R,

=

resistivity of formation water

Rm f

=

resistivity of mud filtrate

(5)

Recovered water is typically comprised of both filtrate and formation water. The filtrate must be deducted from the total water recovery prior to using Eq. 5. The fraction of formation water in the recovered sample can be found from the following equation:

fraction of formation water in the FMT sample, (070)

The necessary resistivity information is obtained as follows. First, measurements of the recovered water

100 80 60

10 8 6

1

2

SP

3

4

(6)

where

Formation Water Recovery (cm3) Formation Water Recovery (cn?) + Oil Recovery (cm3)

%.v %nf - Rrf)

Rrf %lf - &v)

A prediction of the potential water cut may also be made from the recovered fluids. A nomogram given as Fig. 31 can be used to predict water cut. Water cut prediction can also be determined from the following equation: Water Cut (070) =

=

5 6

8

10

20

30

40

50

60

-200 -180 -160 -140 -120 -100 - 8 0 - 6 0 - 4 0 - 2 0 c : : : : : ! ! : : : : : ! : : : : : :

FIGURE 31 Nomogram for estimation of percent water recovered.

25

80

100

0 1

fluorescence tests, may be significant. Detection of gas may also be important provided the gas is free gas and not solution gas associated with formation water (see the following section). As a rule of thumb, if less than lo-15% of the water recovered is formation water and only a small volume or trace of oil is present, the formation is predicted to produce water-free. A high water cut would be predicted if larger amounts (>15%) of formation water are recovered.

resistivity are made by either resistivity cell or titration methods, with the latter being more accurate. Second, formation water resistivity, R,, is determined from well logs W, R,,, etc.), produced water samples from offset wells, water catalogs, etc. Third, the mud filtrate resistivity, R,,, must be determined, again by resistivity cell or titration. A word of caution when determining R,, is in order, however. R,, values are often observed to be too low, sometimes less than the resistivity of the recovered fluid, R,,. This may result from conditioning the mud prior to logging or by an ion exchange mechanism. In any case, the values used for Rmfand R,

Easy recovery of filtrate is indicative of a permeable formation. This factor, coupled with indications of hydrocarbons from openhole logs (even though only filtrate is recovered in the sample tank) may indicate the zone to be a candidate for well completion. The FMT measurements verify a permeable zone which can be productive if hydrocarbons (indicated from other information) are present.

should be checked with logs and mud company reports when their reliability is questioned. Fourth, all resistivities must be adjusted to the same temperature for determination of the fraction of formation water recovered. This is accomplished by using the chart shown

in Fig. 23 or the following equation (ARPS) for NaCl solutions:

Technique For Various Size Recoveries The following method analyzes the recovered fluids by converting the surface-measured volumes to downhole conditions. It is presumed that the sample which entered the tool at downhole conditions is representative of anticipated production. This interpretive approach attempts to break out the formation water, oil, and free gas, if any, at formation pressure and temperature. Note, however, that small amounts of formation water recovery ( p,,) in a specific geologic environment are defined as abnormally high formation pressures (superpressures), whereas formation pressures less than hydrostatic are called subnormal (subpressures).

(27)

Figure 48 and Eq. 27 both illustrate how these subsurface pressures and stress concepts are related:

Overburden Pressure

PO = Pf

This pressure originates from the combined weight of the formation matrix (rock) and the fluids (water, oil, gas) in the pore space overlying the formation of interest. Mathematically, the overburden pressure (p,) can be expressed as:

+C7

(29)

where

Weight (Rock Matrix + Fluid) Area

density of rock matrix

Formation pressure (pf) is the pressure acting upon the fluids (formation water, oil, gas) in the pore space of the formation. Normal formation pressures in any geologic setting will equal the hydrostatic head (i. e., hydrostatic pressure) of water from the surface to the subsurface formation. Abnormal formation pressures, by definition, are then characterized by any departure from the normal trend line.

where yw is the specific gravity of a representative column of water.

PO =

P ma

Formation Pressure

In general then, the hydrostatic pressure gradient (gfp) can be defined in psi/ft from: gfp = 0.433 x yw

= porosity of formation expressed as a fraction

Worldwide observations over the last few years have resulted in the concept of a varying overburden gradient for fracture pressure gradient predictions used in drilling and completion operations.

North Sea, Delaware (older portion Pre Penn.)

9.0

+

Generally, it is assumed that overburden pressure increases uniformly with depth. For example, average Tertiary deposits on the U. S. Gulf Coast and elsewhere exert an overburden pressure gradient of 1.0 psi/ft of depth. This corresponds to a force exerted by a formation with an average bulk density of 2.31 g/cm3. Experience also indicates that the probable maximum overburden gradient in clastic rocks may be as high as 1.35 psi/ft.

Basin Location

0.465

= vertical height of geologic column

Pf

Typical average hydrostatic gradients which may be encountered during drilling for oil and gas are shown below: Hydrostatic Gradient

z

PO

= overburden pressure (total vertical stress, lithostatic pressure)

Pf

= formation pressure (pore fluid pressure, pore pressure)

u

= grain-to-grain presssure (matrix stress, effective stress, vertical rock-frame stress).

(28)

1

- +) prna + +Pf G

38

Overpressures are defined by: pf (Psi 1

= gfp x D + C

(33)

Pf @ia)

= gfp x D + 15 + C

(34)

whereas subpressures (underpressures) are described by pf (Psi)

= gfp x D - C

(35)

pf @ia)

= gfp x D + 15 - C

(36)

Hydrocarbon pressure regimes depart from subsurface water regimes in that the densities of oil and/or gas are less than that of water. Consequently, hydrocarbon pressure gradients are smaller, typical values being Gas Density (g/cm3)

Pressure Gradient (psi/ft)

0.25 0.18

FIGURE 48 Subsurface pressure concepts.

In normal pressure environments (pr = pHY) the matrix stress supports the overburden load due to grain-to-grain contacts. Any reduction in this direct grain-to-grain stress (o-0) will cause the pore fluid to support part of the overburden, the result being abnormal formation pressures (pf > p,,). In other words, the overburden may effectively be buoyed by high formation pressures.

Oil Density (g/cm3)

0.11 0.08 Pressure Gradient (psi/ft)

0.85 0.80

0.37 0.35

where g/cm3 + 2.31 = psi/ft

There are numerous factors that can cause abnormal formation pressures such as surpressures and subpressures. Frequently, a combination of several superimposed causes prevail in a given basin and as such is related to the stratigraphic, tectonic, and geochemical history of the area. This has been discussed in detail (Hawkins, 1956).

APPLICATIONS OF FMT PRESSURE MEASUREMENTS The most important feature of the FMT is its ability to perform pretest pressure measurements with reasonable accuracy at numerous selected depth intervals. Pretest

formation pressures are typically determined following the observation of a stable buildup to formation shutin pressure. It is essential that this formation shut-in pressure reading be taken as long as safely possible after the flowing portion of the pretest in order to allow adequate time for the pressure to build up and approach the actual formation pressure. A typical formation pressure reading is illustrated in Fig. 49. If the pressure test is terminated too early, the formation shut-in pressure reading will be too low since sufficient buildup did not occur.

Generally speaking, any subsurface fluid pressure (pf) is a function of the fluid pressure gradient (gfp) and true vertical depth (D), such as

pf (Psi)

= gfp x D

(30)

gauge pressure units

pf @ia)

= gfpx D + 15 absolute pressure units

gfr, (psi/ft) = pf (psi)/D (ft)

(37)

(31)

Measured Depth vs. True Vertical Depth

(32)

It is also veryimportant that all measured pressure data be evaluated at the true vertical depth (TVD) regardless

In subsurface water pressure regimes, the typical average pressure gradients for fresh and brackish water are 0.433 psi/ft and for salt water, 0.465 psi/ft. These values correspond to fluid density values of 1.0 g/cm3 and 1.07 g/cm3. Figure 19 shows water density as a function of salinity, temperature, and pressure.

of the borehole drift angle. This is illustrated by the example in Fig. 50, where vertical Well A was drilled to 10,000 ft and the measured depth of deviated Well B was 12,000 ft, although the true vertical depth of the target 39

ANALOG (Psi)

B i

RECORDED DIGITAL SAMPLING PRESSURE (Psi)

-L-l-2

FIGURE 49 Adequate time for pressure buildup must be allowed.

40

L

FIGURE 50 Vertical borehole vs. measured depths and TVD in directional boreholes.

zone in Well B was also 10,000 feet. Both wells were drilled with similar mud systems, corresponding to a hydrostatic gradient of 0.465 psi/ft, or 4650 psi at TVD in both wells. Serious interpretive errors would have resulted if measured depth of Well B had been used to calculate hydrostatic pressure (12,000 x 0.465 = 5580 psi), in which case the resultant value would be 930 psi too high.

L

FIGURE 51 Formation pressure gradient.

The shallow zone is slightly underpressured and the deepest zone is considerably overpressured. This type of

information can be invaluable to drilling plans for offset wells and in optimizing completion practices.

Pressure Regimes in Water-Bearing Reservoirs

Supercharging

Subsurface aquifers can have normal (hydrostatic) pressures or they may be either overpressured or underpressured. If a well penetrates a sequence of permeable water sands, FMT pretest pressure measurements can be

Formation pressure measurements can be affected by a set of conditions known as supercharging. Supercharg-

ingis thenaturalresult oftheradialflowofinvadingmud filtrateinto the formation during theprocess of building up a filter cake over a permeable depth interval, as il-

used to identify the normal hydrostatic gradient and locate those strata which are either overpressured or underpressured.

lustrated in Fig. 52. The supercharging effect causes the observed formation pressure (near the wellbore) to be greater than the actual formation pressure. Supercharg-

The plot of depth vs. formation pressure in Fig. 51 is taken from five FMT pretest pressures: 660 psi at 2000 ft, 2325 psi at 5000 ft, 4650 psi at 10,000 ft, 5580 psi at 12,000 ft, and 8150 psi at 12,500 ft.

ing should not be confused with intrinsic formation overpressures. Two mud-related factors which affect the

filtration rate are (1) the degree of pressure differential (or overpressure) between the mud and the formation and (2) the extent of mud cake buildup and its effectiveness in preventing further filtrate fluid loss into the formation. The second factor tends to mitigate the effects of supercharging with time if the zone has adequate permeability to allow the pressure to bleed off and dissipate. Supercharging can be quite large in very tight formations (< 0.5 md) as illustrated by the data in Fig. 53. Plots of pressure vs. depth from several pretest readings will usually reveal these zones which are anomalous because of supercharging as shown in Fig. 53.

The formation pressure gradient (gf,) for each zone is calculated as follows: 660 psi Q 2000 ft 2325 psi @ 5000 ft

grr, =

660/2000

gr, = 2325/5000

= 0.33 psi/ft = 0.465 psi/ft

4650 psi @ 10,000 ft gr, = 4650/10,000 = 0.465 psi/ft 5580 ps1 @I 12,000 ft gg = 5580/12,000

= 0.465 psi/ft

8150 psi @ 12,500 ft gr, = 8150/12,500

= 0.65 psi/ft 41

pressures vs. depth (TVD) presents a quantitative profile of each individual horizon’s ability to drive its produced fluid to the surface. A typical plot of pressures vs. depth (TVD) compared to bulk volume analysis from openhole logs across three potentially productive hydrocarbon zones is shown in Fig. 54. A hydrostatic mud coIumn pressure gradient is also plotted. Maximum advantage of pretest formation pressure data is attained if the pressures used on the plot are derived from the extrapolation of the appropriatepressure and buildup plots. As discussed earlier, buildup pressure data

is a truer representation of formation fluid pressures, especially when rock permeabilities are low. The presentation of the mud column pressuregradient serves as a check to verify proper tool operation during the downhole pressure survey.

FIGURE 52 Supercharging results from radial flow of the mud filtrate into the formation during filter cake buildup.

If a particular stratigraphic unit is relatively thick and undisturbed by prior depletion, a formation pressure profile across that zone may indicate the type of movingpore fluid. Equation 27 applies in this circumstance

just as it did with hydrostatic gradients. gfp (psi/ft) = 0.433 x Reservoir Fluid Density (cm3)

FIGURE 53 Large supercharging effects are most common in tight formations.

Formation water densities generally vary in gradient from 0.433 psi/ft (fresh water) to 0.465 psi/ft and greater for salty waters. Gas zones generally exhibit gradients less than 0.1 psi/ft. Liquid hydrocarbons will vary from 0.25 to 0.34 psi/ft or greater depending on oil gravity and gas/oil ratio (GOR). A key to gradient (or slope) is given in the lower right-hand corner of Fig. 54. FMT fluid pressure gradients therefore play an important role in verifying, or identifying, the presence of water, gas, or liquid hydrocarbons in a formation.

Selection of Test Intervals

Determination of Movable Formation Fluid Density in Zones with High Connate Water Resistivity

Proper analysis of openholelogs should allow selection of themorepermeablezones forpressuremeasurements.

In depth intervals where the reservoir connate water resistivity (R,) is high, and the traditional Archie method of log analysis allows for some uncertainty of pore fluid type, a crossplot of pHY versus p* is recommended. Pressures derived from the Hewlett-Packard

Good log interpretation practices will help the FMT user avoid testing strata where supercharging is likely to occur. In any case, the higher credibility should be given those pressure measurements taken from zones of highest permeability. Very long pretests are indicative of extremely low permeability and likely to be supercharged. Effects of supercharging can be further minimized by running the FMT service as long as possible after mud circulation, which would allow for maximum mud cake buildup and pressure dissipation.

gauges should be utilized because of their superior resolution. With several data points available, a best-fit line or slope can be established. The resultant slope is proportional to the in-situ density of the formation fluid (Pf). Multiplying the slope value by the mud density (P,,d) yields the product Pf. The above assumes static hydraulic equilibrium over the designated depth interval.

Pressure Gradients and Particular Pressure Regimes

Defining Gas/Liquid and Oil/Water Contacts

When an adequate number of formation pressure measurements are acquired in a borehole, a plot of those

Pressure gradients derived from FMT data have also found significant usage in defining gas/liquid and 42

50

0

0

1.19 g/cm3

FMT JOB SUMMARY - PRESSURE

\

HYDROSTATIC

OHYDROSTATIC

0

500

1000

1500

2000

2500

PRESSURE (psi)

FIGURE 54 Comparison of bulk volume analysis from open hole logs to a typical FMT pressure versus TVD depth plot.

oil/water contacts. The free water level indicated in Fig. 55 represents the depth where capillarypressure equals zero. A series of FMT pressure measurements across the

The height (Z) above the free water level is a function of capillary pressures, i. e., differences between permeability, fluid densities, and the rock fluid interfaces. It might also be noted that the oil/water contact is indicated as being several feet above the free water level in Fig. 55. The

oil and water zones were plotted vs. depth. A saturation profile from log analysis is provided on the right side of Fig. 55 for comparison. Note that the free water level point occurs where the oil gradient and water gradient intersect.

oil/water contact represents the depth where oil saturation begins to increase from zero. A transition zone is in-

dicated where oil saturation continues to increase until irreducible water saturation (Si,) is attained. Transition zones may exist well above both the free water level and the oil/water contact due to poor vertical permeability, water saturations greater than irreducible, etc. Completion in the transition zone often results in some water production. There are also occasions where “hydrocarbon shows” are observed in well cuttings and/or cores, but the FMT water gradient verifies that the hydrocarbon is only present in negligible amounts. Keep in mind that the pretest shut-in pressures are derived from the cylindrical portion of the buildup data, affected by the formation fluids some distance from the borehole. Zone Isolation or Communication When multiple potentially productive zones are encountered in the same borehole, it is possible to use I?MT pressure data to determine whether or not hydrostatic communication exists between the zones. As shown in Fig. 56, connected zones differ from each other by the amount ofhydrostaticpressure head between thezones.

When it is considered that the communicating reservoir fluids may be some distance from the wellbore, it may be uncertain whether the connecting fluid is water, oil, or a mixture of the two. If a hydrostatic envelope is drawn from a pressure plot in each zone as shown by the arcs A, B, and C for points a, b, and c of Fig. 56, any overlap or contact of the envelopes (shaded areas) corresponds to a depth at which the zones may be connected. The common overlap region defines a point (depth) at which the apparent separate zones may have a common pressure from which a hydrostatic gradient yielding the individual zone’s pressures is possible. The overlap only indicates the possibility of communication.

FIGURE 55 Comparison of FMT pressure data to a saturation profile from log analysis.

An oil or gas reservoir, under virgin conditions, exhibits two fluid phases near the wellbore, i. e., mud filtrate and either oil or gas. Thepressures of the twointerfaces differ because of the effects of capillary pressure. The oil/water contact lies above the free water level by a distance determined by capillary pressures, grain size, permeability, etc. In the transition zone, the capillary pressure is a function of the wetting phase saturation:

Zones A and B of Fig. 56 overlap below point a and above point b and have a common contact along the oil gradient line between points a and b. The close proximity of the overlapping envelopes would lead one to strongly suspect vertical communication between zones A and B.

PC = PO - pw where PC

= capillary pressure

PO

= oil capillary pressure

PVf

= water capillary pressure

The probability of zone C being connected to either zone A or zone B is less likely. Note that the overlap of hydrostatic gradient from zone C overlaps with the oil gradient from zones A and B at point d in Fig. 56. Point 44

0 FMT FORMATION PRESSURE

OIL GRADIENT-1

POSSIBLE POINT OF COMMON PRESSURE TO ZONES A AND C, BAND C

FIGURE 56 FMT pressure data is useful to determine whether or not hydrostatic communication exists between multiple zones.

45

pressure data therefore plays an important role in identifyingzoneisolation or communication between zones.

d is far removed from the three zones under consideration.

The scenario in the figure could be enhanced with wellto-well log correlations, comparison to seismic interpretations, and detailed stratigraphic analysis from dip data, curve shape studies, and other electrofacies fingerprints.

Furthermore, if the oil/water contact occurs in zone B as indicated by bulk volume log analysis, pressure would only move down to zone C along the water gradient. It must therefore be concluded that zones B and C are not in communication.

Impermeable layers within a reservoir can also be identified from the pretest pressure recordings. The recogni-

It is possible that zones A and C are connected, although excluding zone B from such a vertical communication would appear unlikely. However, no water contact is noted in zone A so a remote possibility of connecting to zone C must be considered.

tion of non-permeable streaks is especially important in manycarbonatereservoirs where the better permeability and higher formation pressures are fundamental to hydrocarbon production.

It is extremely important that interpretations, such as that given in Fig. 56, be made from pressure data taken from virgin reservoirs, i.e, where production has not yet begun. Reservoir depletion from offset wells causes dramatic pressure changes in reservoirs.

Determination of Oil/Water Contact Below Total Depth of the Borehole FMT pressure test data can be combined with the analysis of well logs and used to calculate an approximate depth of the oil/water contact even though the borehole has not penetrated the contact. Such information is obviouslyimportant to the developmentgeologist in order toproperlyselect the geographical location for

In the example in Fig. 57, the pressures in zone 1 are significantly lower than the pressures in zone 2. Although the oil gradients in zone 1 and the upper portion of zone 2 are similar, the two zones are not connected because of the significant difference in the hydrostatic gradient.

offset wells. It also provides the reservoir engineer with needed data for estimating reserves.

Zones 3 and 4 of Fig. 57 are in all likelihood part of the same reservoir, as indicated by the schematic. FMT

The FMT data from the well in Fig. 58 showed a formation pressure of 3280 psi at 7000 feet. The recovered oil has an ‘API gravity of 24’ and agas/oil ratio (GOR) of 200. Using the chart in Fig. 20, a GOR of 200 exhibits a density of 0.85 g/cm3 (or a pressure gradient of 0.37 psi/ft) and assuming a hydrostatic gradient of 0.465 psi/ft for water: p0 (psi)

= gfpo x D + C (oil)

3280

= 0.37 x 7000 + c

or, C (oil)

= 3280 - 2590 = 690

and pW (psi)

= gf,, x D + C (water)

3280

= 0.465 x 7000 + C (water)

or, C (water)

= 3280 - 3255 = 15

Knowing that p0 = pW (p, = 0) at free water level, then 0.37 x D + 690 = 0.465 x D + 15

FIGURE 57 Determining zone isolation from FMT pressure data.

46

0.095D

= 675

D

= 7105 ft, the estimated depth of free water level

3280 OS, li, 700011

DEEPEST POSSIBLE OIL/WATER CONTACT

FIGURE 58 Oil/water contact below TD - oil reservoir.

Reservoir and Zonal Depletion

When several wells in a reservoir are produced, newly drilled offset in-field wells usually detect changes in the formation pressure profile as a result of production. If numerous thin zones are produced, the pressure changes in the offset wells provide a clue as to which zones are being depleted. When a single thick sand is produced, the changes in the pressure profile of the reservoir from a linear fluid gradient indicate that certain parts of the reservoir are preferentially produced over others as shown in Fig. 59. This is often due to higher permeability reservoir sections being depleted more rapidly while the tighter sections maintain their pressure, or to permeability barriers separating various portions of the interval. Detection of these production anomalies may indicate that some changes in the completion practice should be made in order to optimally produce the reservoir during primary production. Monitor Injection Program in In-Field Wells

A closely related application is to monitor reservoir pressure from newly drilled in-field wells during secondary recovery operations. This technique verifies the effectiveness of the injection wells and the pressure maintenance program. A pressure contour map

developed from wireline formation tester data is shown in Fig. 60. It is apparent that the high pressure ridges line up with the bank of injection wells.

FIGURE 59 Pressure profiles can illustrate the parts of a reservoir which show a preference to produce.

per circumstances, be detectable by the FMT. Some

matrix blocks are initially water saturated but later in geologic time the fracture permeability is filled with liquid hydrocarbon. The matrix blocks become partially saturated with the hydrocarbon. If the blocks are large enough, the lower portion of the block remains water saturated until the pressure differential due to hydrostatic and capillary effects is sufficient to displace the water. Above this point, hydrocarbon saturation increases toward irreducible water saturation, which is achieved only in sufficiently large blocks. The FMT response is shown in Fig. 61. The apparent oil gradient corresponds to the overall gradient of the fluid in the fracture, while deviations toward lower pressure are indicated where the FMT was set on the water-saturated portion of the block. The FMT pretest buildup plot deviates from building up to a stationary pressure, indicating that the pressure transient was controlled by the pressure within the fracture volume as shown in Fig. 62. An estimate of fracture block size can be made on the basis of the deviation from spherical buildup as illustrated in Fig. 62. The following two equations have been reported, where h is the block size in cubic centimeters.

Fracture Detection Naturally fractured formations, where interconnected

fractures form a high permeability network among otherwise low permeability blocks may, under the pro-

Based on Pressure Deviation

The average block size may be estimated with the following quadratic equation:

I \*

.

PRODUCING WELL

@ WELL TESTED WITH FORMATION TESTER

l

f INJECTION WELL

.

.

2517

FIGURE 60 Pressure contour map developed from wireline test data.

26

. l \. . . 7

.

22

WELL NUMBER

0 AVERAGE MEASURED 2184 PRESSURE

/-

lFIGURE 62 FMT pressure buildup in a fractured reservoir.

FIGURE 61 FMT pretest pressures through a series of matrix blocks, some of which contain a permeable fracture network.

(2301 x D) h, + (C - 115.1 x D) h - 0.3 = 0

(39)

Extremely Tight Formations

where

If formation permeability is extremely low, the pretest piston will draw a near-vacuum as the formation is essentially drawn down by its full pressure. The FMT drawdown is force limited to 7500 psi below hydrostatic pressure. Once the pretest piston completes its stroke, the formation continues to feed fluid into the pretest system until 10 cm3 is accumulated. (In geographical areas where such formations are common a 5-cm3 plug is often used, limiting the pretest to a 5-cm3 volume.)

C and D

(41)

hb

= average block size, cm3

P*

= extrapolated pressure, psi

Pi

= reservoir pressure, psi

+

= porosity, %

Ct

= matrix fluid compressibility, psi ml

cl

= flow rate, cm3/sec

t

= flow time, set

The lowest possible pressure during a tight pretest is the vapor pressure of the fluid (usually mud filtrate) filling the pretest system. Vapor pressure is a function of temperature, e. g., vapor pressure for water at 300’F is 67 psi. Any drawdown pressure records below the vapor pressure should therefore be caused by temperature effect on the pressure gauge and deviation from the gauge calibration. Newer FMT tools and current software correct thepressuregaugefor temperature effect. If sufficient time is allowed, the pressure will slowly build up to a shut-in formation pressure.

Based on Time of Deviation

An alternate approach based upon time of deviation is reported as follows:

Grain Size Effects Studies of grain size and sorting have shown that a correlation exists to permeability and particular environments of deposition. Studies of log curve shapes

(42)

and their comparison to full core petrographic analysis have shown that characteristic features of fining upward, coarsening upward, etc. can often provide clues to help identifyparticular sedimentary environments. It is also

where t*

= total time elapsed between beginning of flow to deviation from linear buildup, set

At*

= t* - length of flowing time, set

generally accepted that grain size and sorting affect the nature of permeability, with finer grain and/or poorer sorting correlating to lower permeability. 49

A profile of numerous FMT-derived permeabilities vs. depth across a particular formation might also provide such an inference to the original environment of deposition. In a deltaic distributary mouth bar, for example, a permeability profile would be expected to show an increase in permeability upward vs. depth, whereas the spontaneous potential, gamma ray, or other log curves sensitive to grain size change would tend to show a coarsening upward trend. This idealized comparison is shown in Fig. 63.

The purpose of pulse testing is to provide estimates of average transmissibility (kh/p) and storage (Qcth) in the reservoir between the wells being tested. Conventional pulse tests cannot usually provide the horizontal and vertical permeabilities of each layer of strata, information which is critical for optimal design of reservoir management procedures. The FMT can provide the permeability data with the necessary detail. Optimal management of stratified reservoirs requires a knowledge of the transmissibility and storage values of each layer as well as vertical permeabilities across the boundaries between the layers. This is necessary information if the reservoir engineer is to reliably predict how injected fluid will travel through the reservoir during a waterflood, CO, flood, etc. With conventionalpulse testing, it is near impossible to estimate these properties in a stratified reservoir. The FMT can provide the needed information. The FMT procedure requires a minimum of two surveys of the observation well. The first survey is conducted sequentially with the initial suite of openhole logs. Immediately following, a disturbance is created in the adjacent well by alternating flow rates. Following the flow disturbance, a second FMT survey is made in the observation well. The second FMT survey should indicate a different pressure profile than the first survey. From this difference, the degree of vertical and area communication between the two wells in the reservoir can be determined. A numerical reservoir simulator is commonly used to analyze the data. The pressure profiles and pulse rates from the two FMT surveys are history-matched, allowing an estimate of both the horizontal (k,) and vertical (k,) permeabilities of each layer.

FIGURE 63 Grain size studies from logs can be compared to pretest pressure permeability profiles.

FMT Pulse Testing

Saturation changes are usually negligible during the FMT pulse test and are not usually simulated. The short test period virtually eliminates the need to consider other reservoir influences such as production decline, pressure decline, well history, field history, etc.

Pulse testing techniques are widely used to determine the reservoir properties between the adjacent wells involved in the test. Test procedures involve one pulsing well (production or injection) and an observation well to observe pressure response. In order to utilize the FMT, the observation well must be uncased across the reservoir being tested.

FMT REALITY The primary goals of formation pressure testing are to quantify the effective permeability of the reservoir and to evaluate the efficiency of the well. Pressure buildup and pressure drawdown are two of the more popular test variations which are used to evaluate a reservoir.

A series of flow disturbances are created in the pulsing well by alternating production (or injection) with a shutin period. The pressure response to those pulses is measured in the observation well utilizing the downhole pressure gauge. The Hewlett-Packard quartz gauge should be used because the pressure responses are very small, occasionally less than 0.1 psi. Pulse periods are usually of short duration.

Formation Multi-Tester tools provide an avenue for well operators to approach these goals in a quick, relatively inexpensive way. Other wireline services (e. g., produc50

LIST OF SYMBOLS, INCLUDING SUBSCRIPTS

A ‘API C C

ct D AP Appt APS At DST Ef

FMT ffw g

Y

GR GOR GWR h H-P HY k k abs kani kc kcl ke kH

k eo k ew k ro k rw ks k

m

PO PW

Area, ft2 API units of oil gravity Conversion factor Compressibility, psi-’ Compressibility of formation fluid, psi-t Depth, ft or m Pressure differential, psi Drawdown during pretest

MW CJ mm gfP +

P PC

(P formation - Pflowing), Psi

Pf

Drawdown during sampling (P formation - Pflowing), Psi Time increment, min or set Drillstem test Flow efficiency Formation Multi-Tester Formation water fraction, percent Acceleration due to gravity, cm/sec2 or ft/sec2 specific gravity, g/cm3 Gamma ray log Gas/oil ratio, ft3/bbl Gas/water ratio, ft3/bbl Effective formation thickness, ft Hewlett-Packard quartz pressure gauge Hydrostatic Permeability, md Absolute permeability, md Anisotropy (k,/k,) Cylindrical buildup permeability, md Drawdown permeability, md Effective permeability, md Horizontal permeability, md Effective permeability to oil, md Effective permeability to water, md Relative permeability to oil, md Relative permeability to water, md Spherical buildup permeability, md Vertical permeability, md Slope of a pressure buildup curve, psi/cycle Slope of a cylindrical pressure buildup curve, psi/cycle Slope of a spherical pressure buildup curve, psi/cycle Viscosity of gas

pg Pi PO pw

P WS P* PI 9 qpt

r rinv

Rm f Rrf

Rt

RW

P P ma pf %J SG siw SO

SR S W

S x0

SP t V VPC

55

Viscosity of oil Viscosity of water Mud weight, lb/gal or lb/ft3 Matrix stress, psi Parts per million Fluid pressure gradient, psi/ft Porosity, percent Pressure, psi Capillary pressure, psi Flowing pressure, psi Gas pressure, psi Formation pressure, psi Oil pressure, psi Water pressure, psi Pressure at probe after shut in, psi Formation pressure extrapolated from Horner Plot, psi Productivity index Flow rate, cm3/sec or bbl/day Flow rate during pretest (chamber size/time to fill), cm3/sec Probe radius, in. Depth into formation affected by buildup, cm Resistivity of mud filtrate, ohm-m2/m Resistivity of recovered fluid, ohm-m2/m True resistivity of the formation, ohm-m2/m Resistivity of the connate water, ohm-m2/m Density, g/cm3 Matrix density, g/cm3 Fluid density, g/cm3 Gas saturation, percent Gas solubility Irreducible water saturation, percent Oil saturation, percent Solubility ratio Water saturation, percent Water saturation of the flushed zone, percent Spontaneous potential curve, mV Time, min or set Volume of liquid or gas, cm3 or ft3 Variable Pressure Control

Milburn, J.D. and Howell, J.C.: “Formation Evaluation with the Wireline Tester - Merits and Shortcomings:’ J. Pet. Tech. (October 1961).

VPC-FMT Formation Multi-Tester with Variable Pressure Control Water cut, percent WC Compressibility factor Z Vertical height Z

Moran, J.H. and Finklea, E.E.: “Theoretical Analysis of Pressure Phenomena Associated with the Wireline Formation Tester’ J. Pet. Tech. (August 1962).

BIBLIOGRAPHY

Odeh, A.S. and Selig, F.: “Pressure Buildup Analysis, Variable Rate Case:’ J. Pet. Tech. (July 1963).

Beal, C.: “The Viscosity of Air, Water, Natural Gas, Crude Oil and Its Associated Gases at Oilfield Temperature and Pressure:’ Trans. AIME (1946).

Pirson, S.J.: Handbook of Well Log Analysis, PrenticeHall, Inc., Englewood Cliffs, N.J. (1963).

Bonham, L.C.: “Solubility of Methane in Water at Elevated Temperatures and Pressures:’ Bull. AAPG (1978).

Schowalter, T.T.: “Mechanics of Secondary Hydrocarbon Migration and Entrapment:’ Bull. AAPG (1979).

Brown, K.E.: The Technology of Artificial Lift Methods, Vol. I, The Petroleum Publishing Co., Tulsa, Okla. (1977).

Sethi, D.K., Vercellino, W.C., and Fertl, W.H.: The Formation Multi-Tester - Its Basic Principles and Practical Field Applications, SPWLA Twenty-First Annual Logging Symposium (1980).

Chew, J.N. and Connally, C.A.: “A Viscosity Correlation for Gas-Saturated Crude Oil:’ J. Pet. Tech. (1959).

Slider, H.C.: Practical Petroleum Reservoir Engineering Methods, The Petroleum Publishing Co., Tulsa, Okla.

Craft, B.C. and Hawkins, M.F.: Applied Petroleum Prentice-Hall, Inc., Englewood Cliffs, N.J. (1959).

(1977).

Reservoir Engineering,

Standing, M.B.: Volumetric and Phase Behaviour of Oil Field Hydrocarbon Systems, Reinhold Publishing

Log Review I, Dresser Atlas Publication (1974).

Corp., New York (1952).

Log Interpretation Charts, Dresser Atlas Publication

Van Everdinger, A.F.: “The Skin Effect and Its Influence on the Production Capacity of a Well:’ Trans. AIME (1953).

(1983). Fertl, W.H.: Abnormal Formation Pressures, Elsevier Scientific Publishing Co., New York-Amsterdam (1976).

APPENDIX A

Frick and Tayler: Petroleum Production Handbook, McGraw-Hill Book Company (1962).

An example problem utilizing FMT-measured pressures for many of the computations discussed in earlier sections is presented in this Appendix. The FMT pressure record in Fig. A-l will be used through the following computation sequences.

Gunter, J.M. and Moore, C.V.: Improved Use of Wireline Testers for Reservoir Evaluation, SPE 14063 presented at SPE International Meeting on Petroleum Engineering, Beijing, China, March, 1986.

A pretest volume of 10 cm3 with a 0.562-in. diameter probe was used during the pretest. The following derivations will be made from this pretest record:

Hawkins, M.F., Jr.: “A Note on the Skin Effect:’ Trans. AIME (1956). Horner, D.R.: “Pressure Buildup in Wells:’ Proc. Third World Petroleum Congress, Leiden (1951). Katz, D.L., Cornell, D., Kobayashi, R., Poetmann, F.H., Vary, J.A., Elenbaas, J.R., and Weinaug, C.F.: Handbook of Natural Gas Engineering, McGraw-Hill Book Company (1959). Mathews, C.S. and Russell, D.G.: Pressure Buildup and Flow Tests in Wells, SPE Monograph (1967). 56

l

drawdown permeability, k,

l

spherical buildup permeability, k,

l

effective bed thickness from spherical buildup, h

l

cylindrical buildup permeability, k,

l

time estimate for retrieving a 10-liter sample

ms

Permeability from Drawdown

The flowing period begins at recorder time of 31 seconds, indicated as t=O on the log of Fig. A-l, and ends at 39 seconds, indicated as tl =8 seconds. The fluid withdrawn is a filtrate having a resistivity of 0.027 ohm-m at 170’F (76OC) or 120,000 ppm NaCl equivalent. Using the chart of Fig. 24, a viscosity of approximately 0.5 cp would be estimated. The minimum steady-state flowing pressure during drawdown is approximately 900 psi and the pressure builds to about 3930 psi. Drawdown permeability, k,, is determined using the following equation (11):

= 930 psi/set

The computation is

x (0.16 x 3 x 10m5)” = 0.19 md

k, = 1842 x C x From the information above, C

= 0.75

q

= 10 cm3/8 set = 1.25 cm3/sec

c1 d

= 0.5 cp

AP

= 3930 - 900 = 3030 psi

= 0.562 in.

The drawdown permeability, k,, is therefore k, = 1842 x 0.75 x

FIGURE A.2 Spherical buildup plot.

(o.25~~~o) = 0.51md

Effective Bed Thickness Computation Permeability from Spherical Buildup

For this computation, assume that the anisotropy k/k, = 1. From Fig. A-2, the extrapolation of spherical pressure buildup, p*, is 3938 psi, whereas the data deviates toward a higher value of formation pressure, p, of approximately 3940.5 psi (see dashed line). The effective thickness, based on the pressure match criterion, is given by Eq. 22:

The raw data taken from the log of Fig. A-l is tabulated as At, t + At, and the spherical buildup parameter is

&-v& A plot of the pressure recording versus the spherical buildup parameter is given in Fig. A-2. This plot shows the spherical buildup pressure estimate to be 3938 psi and the slope, m,, to be 930 psi/set%. Buildup permeability is given as:

%

Taking the following values for this FMT test, k,/kn

x Q+>”

Pi - Ps* V

Using the FMT pretest data in question, q

= 1.25 cm3/sec

+

= 0.16

ct

= 3 x 10-s

P

= 0.5 cp

=

1 = 2.5 psi = 10 cm3

1%

The bed thickness is calculated to be 10 x 1 l-l’ = 1.2 4rr(2.5)(0.16) x 3 x 1O-5

58

= 48.57 c m = 1.59 m

Permeability from Cylindrical Buildup

The time parameter, t + At/At, for this FMT test was tabulated. The cylindrical buildup (Horner) plot for this test is plotted on Fig. A-3. Extrapolation of the linear data indicates a formation pressure, p* = 3947.6 psi. The slope of the linear portion of the data is m, = 198 psi& cle. For permeability from cylindrical buildup, Eq. 19 is

which, for the data of this FMT test, becomes k, = 88.4

= 0.18 md

Time Estimate for Sampling

An estimate of the time required to retrieve a lo-liter (2.64-gallon) sample may be obtained by using Eq. 2 to estimate the time per gallon. t=

63.1 x Appt qpt x 4

FIGURE A-3 Cylindrical buildup plot.

For the FMT test of Fig. A-l, Appt

= 3930 - 900 = 3030 psi

APS

= 3930 psi (sample is taken against an air cushion chamber)

qPt

= 1.25 cm3/sec

and hence, the time in minutes required per gallon is estimated as 63.1 x 3030 = 38.9 min/gal t= 1.25 x 3930 and 2.64 gal x 38.9 min = 102.7 min (or 1 hr, 42.7 min) to fill a lo-liter (2.64-gal) tank.

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