Formation Evaluation by Tomisin Olapo Page 1

DRILL STEM TESTS

Formation Evaluation by Tomisin Olapo Page 2

DRILL STEM TESTS

1.0 INTRODUCTION:

A drill stem test (DST) is a procedure for isolating and testing the surrounding geological formation through the drill stem. The test is a measurement of pressure behavior at the drill stem and is a valuable way to obtain important sampling information on the formation fluid and to establish the probability of commercial production.

In oil and natural gas extraction, the drill stem includes the drill pipe, drill collars, bottomhole assembly, and drill bit. During normal drilling, fluid is pumped through the drill stem and out the drill bit. In a drill stem test, the drill bit is removed, a drill stem test tool is added, and fluid from the formation is recovered through the drill stem, while several measurements of pressure are being made.

The basic drill stem test tool consists of a packer or packers, valves or ports that may be opened and closed from the surface, and two or more pressure-recording devices. (A packer is an expanding plug which can be used to seal off sections of the open or cased well, to isolate them for testing. The drill stem test tool is lowered on the drill pipe to the zone to be tested. The packer or packers are set to isolate the zone from the drilling fluid column, the tester valve is opened, and testing begins.

1.1 BACKGROUND OF STUDY:

Working in El Dorado, Arkansas, in the 1920s, E.C. Johnston and his brother M.O. Johnston

developed the first drill stem tester and ran the first commercial drill stem test in 1926. In April

1929, the Johnston Formation Testing Corporation was granted a patent (U.S. Patent 1,709,940)

and they subsequently refined the testing system in the early 1930s.

In the 1950s, Schlumberger introduced a method for testing formations using wireline. The

Schlumberger formation-testing tool, placed in operation in 1953, fired a shaped charge

through a rubber pad that had been expanded in the hole until it was securely fixed in the hole

at the depth required. Formation fluids flowed through the perforation and connecting tubing

into a container housed inside the tool. When filled, the container was closed, sealing the fluid

sample at the formation pressure. The tool was then brought to the surface, where the sample

could be examined. In 1956, Schlumberger acquired Johnston Testers and continues to perform

drill stem tests and wireline formation tests in both open and cased holes.

Formation Evaluation by Tomisin Olapo Page 3

1.2 AIMS AND OBJECTIVES:

To give an overview on the working principles of Drill Stem Tests and its application to drilling,

well testing and reservoir optimization.

1.3 WHY DRILL STEM TESTS?

Drill Stem Tests is used primarily to determine the fluids present in a particular

formation and the rate at which they are produced.

A temporary well completion to gather information on the potential productivity of a

formation

Despite the tremendous value of core analysis and well logging some doubt always

remains concerning the potential productivity of an exploratory well

WE NEED TO KNOW:

if there is a reservoir?

what does it contain?

at what rate will it produce?

for how long?

what facilities will be required and when?

what hazards are there?

Formation Evaluation by Tomisin Olapo Page 4

2.0 LITERATURE REVIEW:

Geologists are well aware of the relevance of abnormal pressure to hydrocarbon accumulations

in the Uinta and Piceance Basins (Lucas and Drexler, 1976; Johnson, 1989b; Wilson and others,

1998). As Law and Spencer (1998, p. 2) have noted, “***(knowledge of) the large number of

abnormally pressured areas in the Rocky Mountain region of the United States is a

consequence of several detailed investigations of abnormally pressured, unconventional gas

reservoirs. In this region and elsewhere in North America, investigators have noted the close

association of hydrocarbon accumulations, particularly unconventional gas accumulations, and

abnormal pressures.” Much of the oil and gas in the Uinta and Piceance Basins occurs in basin-

centered (continuous) systems. Consequently, knowledge of abnormal pressuring in these

basins is of especial interest, because basin-centered gas accumulations are nearly always

associated with abnormal pressures (Law and Spencer, 1998).

Although the need for accurate determinations of formation pressure in the characterization of

basin-centered res-ervoirs is well established, the determination of formation pressure itself is

anything but straightforward. Holm (1998) ranked the methods of obtaining formation pressure

in the following order: repeat formation tester, drill-stem tests, mud-weight data, and pressure

kicks. Drill-stem tests (DSTs), which are the subject of this report, measure the down-hole

pressure of fluid within the wellbore, rather than the formation pressure itself. DST results

must be extrapolated and corrected carefully in order to obtain the best estimate of true

formation pressure (Holm, 1998). No such analyses were carried out in this study, which simply

presents the unanalyzed pressure data from a large number of DSTs within the Uinta and

Piceance Basins. It is believed that the bias imposed by this lack of detailed analysis

underestimates the formation pressure in a certain fraction of cases, as discussed below. As a

reminder of this bias, a measurement is described as apparent pressure or apparent pressure

gradient.

The DST pressure data are presented in compact graphs arrayed in map-like format

(“checkerboard plots”) and in con-ventional plots of pressure versus depth. The pressure data

have not been integrated with stratigraphy or indicators of thermal maturity; the analysis is

limited to comments on the validity of the data and the distribution of overpressured

conditions. The results appear most informative in the Altamont-Bluebell field of the Uinta

Basin, moderately informative in the eastern Uinta Basin, and rather disappointing in the

Piceance Basin.

As utilization of ground water and ground-water reservoirs increases the importance of having

knowledge on regional ground-water systems also increases. Understanding these systems

often requires hydrologic data from great depths. In some areas such information may be

available from pumping tests made during the course of petroleum exploration. The usual

Formation Evaluation by Tomisin Olapo Page 5

hydrologic test performed by the petroleum industry is the drill-stem test. The oil industry

developed the drill-stem test as a method of sampling the fluid in a subsurface formation

during the course of drilling operations. Most modern drill-stem tests, however, yield three

types of hydrologic data:

1) A sample of the formation fluid,

2) The undisturbed formation pressure, and

3) A coefficient of permeability for the stratigraphic interval tested.

During the drill-stem test the stratigraphic interval of interest is isolated in the hole by the use

of packers attached to the drill string and is allowed to yield fluid into the drilling pipe under the

influence of the formation head. The arrangement of down-hole components in a typical drill-

stem test string is shown in Figure 1.In the usual relatively shallow test the drill pipe initially is

completely empty and open to atmospheric pressure. By opening the tester valve in the test

string

Fig 1: DST assembly using two

straddle packers showing the main

components of a typical drill stem

test steering.

Formation Evaluation by Tomisin Olapo Page 6

2.1 BASIC THEORY OF DRILL STEM TESTS

Mathematical analysis of the test results is based upon the diffusion equation first applied to

problems of heat flow. Theis (1935) showed the usefulness of this equation for analyzing fluid

flow to producing water well. Muskat (1937) suggested the following form of the differential

equation for petroleum problems which applies to horizontal radial flow through a unit

thickness of the producing formation.

The concept of storage as expressed in equation 1 is somewhat different from the concept of

storage used in ground-water theory. Storage is expressed in equation 1 by the factors f and c,

which include only the compressibility of fluid within the producing formation. Muskat in a later

publication (1949), following both Theis (1935) and Jacob (1940), modified the concept to take

into account not only the compressibility of the fluid but also deformation of the aquifer

skeleton. Horner (1951) suggested a method to analyze the pressure recovery during a drill-

stem test based upon the following solution to the basic equation:

Formation Evaluation by Tomisin Olapo Page 7

The analysis is equivalent to that suggested by Theis (1935).for analysis of recovery tests in

water wells. Horner's solution like Theis's, is based on the fact that with sufficient time the Ei

function (the exponential integral) may be closely approximated by a logarithmic function.

Horner (1951) states that thecriteria for applying the equation is:

where rw = radius of the well. For the usual situation, the theoretical error in using equation 2

would be very small in a matter of a few seconds to a few minutes. The coefficient of

transmissibility as the term is used in ground-water terminology is comparable to the terms

kh/µ in equation 2. The viscosity, which is neglected in the usual ground-water problem,

becomes significant when considering many regional groundwater systems. For example, in the

Big Horn Basin, Wyoming, the temperature of fluids within the Tensleep Sandstone varies from

approximately 48° F near theoutcrop area to something in excess of 300° F in the deeper parts

of the basin. This change in temperature produces a change in viscosity from approximately 1.4

centipoises to less than 0.2 centipoise, affecting the ease with which fluid may move in the

system by a factor of approximately 7. The practical solution to equation 2 is made by plotting

log (t0 + At)/At against pq,. Pressure-versus time data are taken from the pressure chart (Figure

2). As suggested above, the theory is developed to analyze the recovery in the shut-in pressure

following a period of production. An example of a plot of log (t0 + At)/At versus p, is shown in

Figure 3. The points should fall on a straight line if the assumptions on which the mathematical

model is based are closely approximated to the field.

Formation Evaluation by Tomisin Olapo Page 8

3.0 MODE OF OPERATION:

Fig. 2: Schematic representation of a

Drill Stem Tester

Fig 3: Test Tree; Basically all it is, is a

combination of valves That are made up on

top of the test string and will divert the

formation fluid to the choke and on to the

separators.

The surface test tree must be equipped with

swab, master, kill and flow valves. A swivel,

positioned above the master valve, must also

be incorporated to allow rotation of the

string.

The test tree should be able to be hung off in

a standard drill pipe elevator and must have

connections for kill and flow lines facing

down.

Formation Evaluation by Tomisin Olapo Page 9

The typical drill stem test will be split into four periods, Pre flow. Initial shut in period, a main

flow period and a final shut in period. Times of for each test are dependent on conditions at

the well site Drill stem tests may be run at any time during the drilling operation at the current

depth or may be used to test any interval in the hole after TD has been reached. Using these

data and based on the evaluation of engineers and geologists, management can base a decision

to complete the hole for potential production of oil or gas or proceed with abandonment.

- Pre- flow Period: is a production period to clean up the well and is used to remove any

supercharge given to the formation due to mud infiltrating into the prospective

formation during the drilling operation.

- Initial shut-in Period: This period is to allow the formation to recover from pressure

surges caused during the pre-flow. this is often referred to as "closed in for the pressure

build up" this period will be longer.

- Main Flow Period: a more lengthy production period designed to test the formations

flow characteristics more rigorously. Samples of any fluids will be checked for water

content Gas bubble bust pressure temperature and many other nice surprises. This will

be done using set choke or variable chokes. Sample reaching surface will be measured

as to volume and gathered for analysis in a laboratory. Samples of any fluids in the drill

string at the conclusion of the test will be measured as to volume and gathered for

analysis. Flowing pressures and temperatures will be recorded.

- Final Shut-in Period: formation pressure is recorded over this period. The shape of the

pressure build up curve will tell us the permeability of the formation, the degree of

formation damage (likely caused during the drilling operation), It will also tell us if we

have found a small reservoir but there is no telling if it a big one.

Fig. 4: Basically all the test choke is, is a

combination of valves That are made up on

top of the test string and will divert the

formation fluid to the choke and on to the

separators.

The surface test tree must be equipped with

swab, master, kill and flow valves. A swivel,

positioned above the master valve,

must also be incorporated to allow rotation

of the string.

The test tree should be able to be hung off

in a standard drill pipe elevator and must

have connections for kill and flow lines

facing down.

Formation Evaluation by Tomisin Olapo Page 10

DRILL STEM TEST PROCEDURE:

Lowering of DST tool

Opening the bypass valve

Sealing the hole by packers

Rotation of Drill string and flow of formation fluid

formation fluid flow

shut in valve and building of pressure

Removing DST tool

Drillstem Testing (DST) is a valuable tool in the oil and natural gas extraction process. Drillstem Testing is a procedure to determine the productive capacity, pressure, permeability or extent of an oil or gas reservoir. Drill stem testing is essentially a flow test, which is performed on isolated formations of interest to determine the fluids present and the rate at which they can be produced. By employing parts such as a DST bottomhole assemblies (BHA) application tests can be done to determine the viability and commercial productivity of a well within an accelerated time line as well providing lower financial risk compared to conventional well testing methods. Basic Drill Stem BHA consist of a packer or packers, which act as an expanding plug to be used to isolate sections of the well for the testing process, valves that may be opened or closed from the surface during the test, and recorders used to document pressure during the test. In addition to packers a downhole valve is used to open and close the formation to measure reservoir characteristics such as pressure and temperature which are charted on downhole recorders within the BHA.

Formation Evaluation by Tomisin Olapo Page 11

4.0 APPLICATIONS OF DRILL STEM TESTS

Cased Hole

Performed after the well is cased, cased hole drill stem testing uses a retrievable production

packer that is set above the zone of interest. The well is then flow tested through perforations

in the casing. The two types of cased hole testing are pressure operated and mechanically

operated. More details

Open Hole

Because it's performed before casing is run, open hole drill stem testing can be the most

economical way to determine productive (see below) capacity, pressure, permeability or the

extent of an oil or gas reservoir. The testing equipment is run into the well and the zone of

interest is isolated using inflate or compression-set packers, depending on your requirements

and drilling conditions. More details

Alternate Procedures

Depending on testing objectives and scope of work DST may also be performed in combination

with various other exploration and completion process such as fluid loss control and well

control, closed chamber tests, well stimulation, and a combination of DST and TCP.

ADVANTAGES OF DST

Reasonable sample of formation fluid

Can find fluid potential directly

Gives better measurements than others

Proves reserves by producing hydrocarbons

DISADVANTAGES OF DST

Not very economical

Very time consuming

Quantitative analysis is not highly accurate.

POINTS OF PARTICULAR IMPORTANCE:

Condition of the hole

Pressure Surges

Operating conditions

Formation Evaluation by Tomisin Olapo Page 12

5.0 REFERENCES

Bradley, J.S., and Powley, D.E., 1994, Pressure compartments in sedi-mentary basins, a review,

in Ortoleva, P.J., ed., Basin compartments and seals: American Association of Petroleum

Geologists Memoir 61, p. 3–26.

Collins, A.G., 1992, Properties of produced waters, Chapter 24 in Brad-ley, H.B., ed., Petroleum

engineering handbook: Society of Petro-leum Engineers, Richardson, Texas, 23 p.

Engelder, T., and Leftwich, J.T., Jr., 1997, A pore-pressure limit in overpressured South Texas oil

and gas fields, 1997, in Surdam, R.C., ed., Seals, traps, and petroleum systems: American

Association of Petroleum Geologists Memoir 67, p. 255–268.

Holm, G.M., 1998, Distribution and origin of overpressure in the Central Graben of the North

Sea, in Law, B.E., Ulmishek, G.F., and Slavin, V.I., eds., Abnormal pressures in hydrocarbon

environments: American Association of Petroleum Geologists Memoir 70, p. 123–144.

History of Petroleum Engineering, API Division of Production, New York City, 1961, pages

561–566

Hunt, J.M., Whelan, J.K., Eglinton, L.B., and Cathles, L.M., III, 1998, Relation of shale porosities,

gas generation, and compaction to deep overpressures in the U.S. Gulf Coast, in Law,

Law, B.E., and Spencer, C.W., 1998, Abnormal pressure in hydrocarbon environments, in Law,

B.E.,

Leftwich, J.T., Jr., and Engelder, T., 1994, The characteristics of geo-pressure profiles in the Gulf

of Mexico Basin, in Ortoleva, P.J., ed., Basin compartments and seals: American Association of

Petro-leum Geologists Memoir 61, p. 119–130.

Lucas, P.T., and Drexler, J.M., 1976, Altamont-Bluebell—A major, natu-rally fractured

stratigraphic trap, Uinta Basin, Utah, in North Ameri-can oil and gas fields: American Association

of Petroleum Geolo-gists Memoir 24, p. 121–135.

Muskat, Morris. 1937. The flow of homogeneous fluids through porous media. McGraw-Hill,

New York. 763 p.

Muskat, Morris. 1949. Physical principles of oil production. McGraw-Hill, New York. 922 p.

Formation Evaluation by Tomisin Olapo Page 13

Spencer, C.W., 1987, Hydrocarbon generation as a mechanism for overpressuring in Rocky

Mountain region: American Association of Petroleum Geologists Bulletin, v. 71, no. 4, p. 368–

388.

Theis, C. V. 1935. The relation between the lowering of the Van Everdingen, A. F. 1953.The skin

effect and its influence on the productive capacity of a well.

Van Poollen, ll. K. 1960. Status of drill-stem testing techniques and analysis, in formation

evaluation. Am. Inst.Mining Metall. Petroleum Engineers, p. IV-21-IV-38.

"Society of Petrophysicists & Well Log Analysts glossary". Retrieved 12 September 2006.

"Society of Petrophysicists & Well Log Analysts glossary". Retrieved 12 September 2006.

Formation Evaluation by Tomisin Olapo Page 14

WIRELINE FORMATION TESTERS

Formation Evaluation by Tomisin Olapo Page 15

WIRELINE FORMATION TESTER 1.0 INTRODUCTION

A formation fluid sampling device, actually run on conductor line rather than wireline, that also logs flow and shut-in pressure in rock near the borehole. A spring mechanism holds a pad firmly against the sidewall while a piston creates a vacuum in a test chamber. Formation fluids enter the tes5t chamber through a valve in the pad. A recorder logs the rate at which the test chamber is filled. Fluids may also be drawn to fill a sampling chamber. Wireline formation tests may be done any number of times during one tip in the hole, so they are very useful in formation testing. Wireline formation testers serve a number of useful purposes, including obtaining a sample of formation fluid, gauging formation permeability, and measuring formation pressure to determine formation pressure gradients. Wireline formation testers have been used for many years to recover samples of formation fluid both in open and cased holes. Traditional tools suffered from a number of drawbacks, such as lack of resolution and accuracy of pressure gauges, and the inability of the instrumentation to tell the operator whether or not a good packer seal was obtained until it was too late to rectify the situation.

1.1 BACKGROUND OF STUDY

First used in the early 1980's

Early tools suffered poor resolution and accuracy of pressure gauges.

Often good formation seals could not be monitored in real-time.

1.2 AIMS AND OBJECTIVES

To give an overview on the working principles Wireline Formation Testers and its application to

drilling, well testing and reservoir optimization.

1.3 WHY WIRELINE FORMATION TESTERS?

Measure formation pressures accurately

Take several formation fluid samples without mud filtrate contamination

Take true PVT samples

Estimate formation permeability and formation damage

Determine gas/oil/water gradients and fluid contacts

Rw and Sw determination

Formation Evaluation by Tomisin Olapo Page 16

2.0 LITERATURE REVIEW

Wireline formation testers serve a number of useful purposes, including obtaining a sample

of formation fluid, gauging formation permeability, and measuring formation pressure to determine formation pressure gradients.

Wireline formation testers have been used for many years to recover samples of formation fluid both in open and cased holes. Traditional tools suffered from a number of drawbacks, such as lack of resolution and accuracy of pressure gauges, and the inability of the instrumentation to tell the operator whether or not a good packer seal was obtained until it was too late to rectify the situation.

The Formation Tester is a tool which is run in either open or cased holes on a conventional

logging cable. Tests may be made rapidly and safely at various depths in the hole. The

Formation Tester provides: a sample of the formation fluids, GORs, a means to determine

accurate gas-oil, or oil-water contacts, bottom hole pressure data, an index to the permeability

of the small zone adjacent to the tool.

There are many formation testing problems peculiar to soft formations. Development of

solutions has been very successful. The problems encountered and their solutions were:

1. The percentage of successful tests was less than expected because unconsolidated sands would

not support the packer. This problem was almost completely solved by the introduction of the

shaped charge and snorkel testers.

2. The number of fishing jobs needed to be reduced. This problem was overcome by keeping the

cable in constant motion so that hydrostatic pressure could not seal the cable to the wall of the

hole.

3. Interpretation was confusing. It was found after many tests that the amount of oil or gas

recovered was the factor which determined what the ultimate production would be. The water

produced should not be used as an indicator of final production.

The Wire Line Formation Tester has recently been used in cased holes with very good success.

The operation and application are similar to those in open holes with the following additional

applications: old wells may be tested, cement jobs can be evaluated for channeling, directional

holes may be tested without wire line hazards.

These inadequacies have now largely been overcome by the introduction of two key features of

modern repeat formation testers, namely quartz crystal pressure gauges and pretest

capabilities that allow the operator to rectify a bad seal before it leads to undesirable results.

An added bonus is the ability of these tools to make pressure tests independent of sample

taking. Indeed, in practice nowadays it is quite common to use these tools solely to make

pressure tests.

Formation Evaluation by Tomisin Olapo Page 17

When ordering the service, give plenty of notice to the service company. Variables such as

sample size, packer hardness, choke size, pressure gauges, and water cushions may not be

universally available. If a sample of recovered hydrocarbons is needed for PVT lab analysis, a

special pressure cylinder should be requested.

When running the tool, a valid test is one that recovers significant quantities of fluid and/or

records formation and hydrostatic pressure.

A dry test is indeterminate, and the tool should be repositioned several times to determine

whether the formation is impermeable (in which case all tests will be dry) or the tool was set in

a shale or tight streak (in which case repositioning should result in a valid test).

A lost packer seal is also indeterminate. In that case, the tool should be repositioned. Openhole

logs are particularly helpful in resolving dry tests and lost packer seals. The microlog, if

available, is useful as an indicator of tight streaks, and caliper logs, particularly the four-arm

type, are useful for avoiding hole conditions leading to lost packer seals.

Fig. 1: schematic of the tool’s

sampling system

Formation Evaluation by Tomisin Olapo Page 18

2.1 BASIC THEORY OF THE WORK

The Wireline Formation Tester is lowered in the hole until the snorkel is opposite the zone of

interest. Tool hydraulics is deployed to open the rubber packer and backup arms and seal

against the borehole wall. Hydraulic pressure, 1500psi above hydrostatic pressure is usually

sufficient to obtain a good seal. This stops any borehole mud contaminating the formation fluid

sample being tested. The snorkel is then deployed or extracted at various rates and volumes, to

draw the formation fluid into the pre-test chambers of the tool. Pre-test chambers are typically

0-30cc in volume. After a few moments the snorkel deployment is then ceased and the

formation pressure build-up is then monitored and recorded. Further deployment of the

Figure 2: Schematic

representation of the Wireline

Formation Tester

Formation Evaluation by Tomisin Olapo Page 19

snorkel will draw the formation fluid into sample chambers attached at the bottom of the tool.

The fluid samples are stored at formation pressures that help in determining hydrocarbon

composition.

Depending upon the formation permeability, pressure build-up times can vary from seconds for

high permeability (>5mD) to hours for low permeability (<0.1mD). Often tool hydraulic pressure

can slowly dissipate if fluid or pressure sampling takes 1 hour or more. This may result in a lost

formation seal and formation fluid contamination with the borehole mud.

Some tools require different tool accessories need to be used depending upon borehole

conditions. Hard or soft packers, different packer sizes, different sample chambers sizes and

types and choke sizes all need to be planned before the logging job.

Wireline Formation Tester tools can typically operate in borehole sizes ranging from 7" to 19" in

diameter. This depends upon the design of each tool and it's specifications.

Formation Evaluation by Tomisin Olapo Page 20

3.0 MODE OF OPERATION

Since the tool is stationary in the hole during the test, the recording is made on a time scale

with increasing time in the down-hole direction on the log. Notice that in track 1, pressure is

recorded in analog form. Four subtracks record the units, tens, hundreds, and thousands of psi.

Each record shows the following pressures:

Before tool is set--hydrostatic

During pretest--drawdown

After pretest—buildup

After buildup--formation pressure

The standard gauge used in the RFT is a strain gauge calibrated by a "dead weight" tester. The

accuracy of this system, after applying temperature corrections, is 0.41% of full scale, i.e., 41 psi

for a 10,000 psi gauge. The resolution of the gauge is about I psi, with a repeatability of 3 psi.

The accuracy may be improved to 0.31% full scale if a special calibration technique is employed

involving placement of the gauge and the downhole electronics in a temperature-controlled

oven.

In some cases, a further pressure difference may be noted between the two gauges, since the

strain gauge is calibrated in psig and the quartz gauge is psia.

Interpretation In order to make the greatest use of RFT data, the analyst should be able to

interpret the following types of RFT records:

pretest records for formation permeability

Post pretest buildup for formation permeability

Llarge-sample fill-up time for formation permeability

Sequential pressure readings versus depth for pore pressure gradients

Large-sample collection data for expected formation product ion

The magnitude of the pressure differential (DP) between pretest sampling pressure and

formation pressure coupled with the flow rate during pretest is sufficient to define

permeability. In general, this may be found by a relation of the form

k = A • C • q • µ / DP

where:

k is permeability in millidarcies

A is constant to take care of units

Formation Evaluation by Tomisin Olapo Page 21

C is the flow shape factor

q is the flow rate in cc/second

µ is the viscosity of the fluid in cp

DP is the drawdown in psi

A number of flow regimes may exist around an RFT tool and the borehole. It is generally agreed that the flow is somewhere between hemispherical and spherical. Computer modeling of the probe/formation system for one service company’s tool shows that the combination of constants A • C to be used should be such that

The flow rate is derived by dividing the 10 cc volume of the pretest chamber by the sampling time read from the pressure record. The viscosity, µ is considered to be that of the mud filtrate and may be estimated from published charts. DP is read from the pressure recording as the difference between pretest sampling pressure and formation pressure.

The pretest method of permeability determination has these limitations:

If the permeability is very high, the drawdown is very small and cannot be measured accurately.

If the permeability is very low, the sampling pressure may drop below the bubble-point, in which case gas or water vapor is liberated and theflow rate of the liquid withdrawn is less than the volumetric displacement rate of the pretest pistons.

The volume of formation investigated is small and hence the permeability measured may be that of the damaged zone, if present, and thus not representative of the formation as a whole.

In general, a good estimate of formation permeability may be obtained from a visual inspection

of the pretest record.

Formation Evaluation by Tomisin Olapo Page 22

Empirical charts then link recovered volumes to predicted production. Three areas are delineated on the chart indicating formations that are gas, oil, and water productive. An estimate of water cut can also be made using:

Formation Evaluation by Tomisin Olapo Page 23

4.0 APPLICATIONS

When investigating zones of interest in which conventional tests are not feasible, such

as those too far above TD, those lacking good intervals for setting straddle packers, or

those with very short intervals, where depth control is critical

For pinning down water-oil, gas-oil, or gas-water contacts

When rig time is critical

When pressure control is critical because of time of day or rig locations

Formation Evaluation by Tomisin Olapo Page 24

5.0 REFERENCES

http://www.onepetro.org/mslib/servlet/onepetropreview?id=SPE-001244-G

http://ipims.com/data/fe11/G40095TA.asp?UserID=&Code=35969

http://www.petrolog.net/webhelp/Logging_Tools/tool_fet/fet.html

Formation Evaluation by Tomisin Olapo Page 25

NUCLEAR MAGNETIC RESONANCE (NMR) LOGGING

Formation Evaluation by Tomisin Olapo Page 26

NUCLEAR MAGNETIC RESONANCE (NMR)

1.0 INTRODUCTION

This summary of the state of the art in nuclear-magnetic-resonance (NMR) well-logging

technology is aimed at nonspecialists who would like to gain some knowledge of the formation-

evaluation capabilities of NMR logging tools. The objective is to explain the basic measurement

principles and interpretations needed to understand NMR formation-evaluation techniques and

to discuss a few examples of these methods. Introduction of pulsed-NMR logging tools in the

1990s provided the industry with unique, even revolutionary, new methods for analyzing

reservoir fluids, rocks, and fluid/rock interactions. The introduction of this technology came at

an opportune time. It coincided with rapidly declining production after the 1970s drilling boom

and the need for new tools to evaluate the more complex reservoirs being explored and

developed. Pulsed-NMR logging tools brought a wealth of new and unique formation-

evaluation applications, and this technology has grown rapidly since its inception. Today, major

service companies (e.g., Baker Hughes, Halliburton, and Schlumberger) offer NMR logging

services.

1.1 BACKGROND OF STUDY

The potential value of NMR logging was first recognized in the 1950s, leading to development

of nuclear-magnetic-logging (NML) tools in the early 1960s. NML tools had many limitations and

eventually were retired from service in the late 1980s. In spite of these limitations, laboratory

research conducted to support NML logging anticipated many formation-evaluation

applications in use today. These applications include estimation of permeability, pore-size

distribution, free-fluid volume, oil viscosity, and wettability. The modern phase of NMR logging

can be traced to the initiation of an NMR borehole-logging research project at Los Alamos Natl.

Laboratory in 1978. The goal of this project was, in part, to build and test a borehole NMR

logging tool that would overcome the limitations of the NML tools. The Los Alamos

experimental tool used strong permanent magnets and performed pulsed-NMR spin-echo

measurements like those used in modern laboratory-NMR instruments. The value of these

measurements is that they are extremely flexible and can be tailored to fit many different

formation-evaluation applications. The Los Alamos tool demonstrated feasibility but did not

meet the requirements for a commercial tool because the signal-to-noise (S/N) ratio was too

low and the magnet and radio-frequency (RF) coil design produced a large borehole signal.

Soon after this demonstration of feasibility, Numar Corp., a company founded in 1983, and

Schlumberger began independent research efforts to design NMR magnets and RF antennas

Formation Evaluation by Tomisin Olapo Page 27

that would be suitable for commercial NMR logging measurements. These efforts came to

fruition in the early 1990s when both companies began field tests of prototype wireline tools.

These tools were vastly superior to the NML tools and quickly had an effect on formation

evaluation. Since introduction of the first commercial tools, both companies have introduced

advanced NMR wireline tools as well as logging-while-drilling (LWD) NMR tools. Numar was sold

to Halliburton in 1997 and operates today as a wholly owned subsidiary. In 2001, Halliburton

introduced an NMR fluid analyzer that is part of its wireline fluid-sampling tool. Halliburton and

Schlumberger introduced LWD tools in 2000 and 2002, respectively. Baker Hughes introduced a

wireline NMR tool in 2004 and an LWD NMR tool in 2005.

1.2 AIMS AND OBJECTIVES

To give an overview on the working principles Nuclear Magnetic Resonance (NMR) tools and its

application to drilling, well testing and reservoir optimization.

1.3 WHY NMR?

These tools impose an external magnetic field in the formation and make a measurement that

is proportional to the porosity, regardless of lithology. This allows identification of the free-

and bound-fluid volumes and the free-fluid type (gas, oil or water). It also provides an indication

of permeability.

Formation Evaluation by Tomisin Olapo Page 28

2.0 LITERATURE REVIEW

Modern NMR Logging

Pulsed-NMR Logging Tools. The sensor (i.e., magnet and antenna) is the heart of a pulsed-NMR

logging tool. It has a significant effect on important tool characteristics including S/N ratio,

minimum echo spacing, depth of investigation (DOI), logging speed, and vertical resolution.

Available tools all have somewhat different sensor designs. Further differences are electronics,

firmware, pulse sequences, data processing, and interpretation algorithms. Detailed logging

specifications for NMR tools can be found on service company websites.

Fig. 1 is a schematic of Schlumberger’s NMR wireline logging tool. This tool has three antennas

and a fully programmable pulse sequencer and can perform a large variety of different

measurements. 2 Two 6-in. antennas are used for making high-resolution measurements of

NMR-derived total, bound-fluid, and free-fluid porosities. The high-resolution antennas are also

used to detect gas and light hydrocarbons and to provide estimates of permeability and pore-

size distributions. The main antenna is 18 in. long. It provides a variety of NMR measurements

made at multiple frequencies for different formation-evaluation applications. Each frequency

corresponds to a different DOI in the range from 1.5 to 4 in., measured from the borehole wall.

The formation-evaluation applications provided by the main antenna include all of those

provided by the two high-resolution antennas, and it is used for radial profiling of fluid types,

fluid volumes, and oil viscosities.

Formation Evaluation by Tomisin Olapo Page 29

Some features are common to all commercial NMR tools. For instance, the tools all use

powerful samarium cobalt permanent magnets that are relatively insensitive to changes in

temperature. The magnets are used to polarize (i.e., magnetize) the hydrogen nuclei (protons)

in hydrocarbon and water molecules. Another common feature is that they all perform pulsed

NMR measurements.

2.1 BASIC THEORY NMR

The NMR measurement comprises two steps. The first step is to create a net magnetization of

the reservoir fluids. The magnitude of Bo typically is a few hundred gauss in the near-wellbore

region (within a few inches of the borehole wall). The magnitude of Bo decreases with the

radial distance from the magnet, which causes a magnetic-field gradient or distribution of

gradients over the measurement volume.

As discussed below, the magnetic-field gradient is used to identify and characterize the fluids in

the reservoir. Before exposure to Bo, the magnetic moments of the hydrogen nuclei are

randomly oriented so that the fluids have zero net magnetization. During the polarization time,

Tp, the magnetization grows exponentially toward its equilibrium value, Mo. The time constant

that characterizes the exponential buildup of the magnetization is the longitudinal relaxation

time, which is referred to as T1. The T1 buildup of the magnetization during the polarization

time is shown in Fig. 2a.

Formation Evaluation by Tomisin Olapo Page 30

In reservoir rocks, a distribution of T1 values is needed to describe the magnetization process.

The T1 distribution reflects the complex compositions of hydrocarbons and the distribution of

pore sizes in sedimentary rocks. A polarization time equal to at least three times the longest T1

is used to ensure that adequate magnetization is achieved. If a polarization time is too short,

NMR-derived porosities underestimate true formation porosities. Immediately following the

polarization time, a train of RF pulses is applied to the formation. The first RF pulse is called a

90° pulse because it rotates the magnetization vector, which initially is parallel to Bo, into the

transverse plane perpendicular to Bo. Once the magnetization is in the transverse plane, it

rotates around Bo, producing a time-varying signal in the same antenna used to create the

pulses. An NMR free-induction-decay (FID) signal first occurs immediately after the 90° pulse

but decays too fast to be detected. The 90° pulse is followed by a series of evenly spaced 180°

pulses that are used to refocus the magnetic moments of the hydrogen nuclei to form coherent

spin-echo signals. The spin echoes are recorded between each pair of 180° pulses. The RF

pulses and spin-echo signals are shown schematically in Figs. 2b and 2c, respectively. The

signals are called echoes because they reach maximum amplitude at the midpoint between

each pair of 180° pulses and then decay rapidly to zero before the following pulse, which

refocuses the magnetic moments to produce the next echo. The RF pulses and associated spin

echoes in Figs. 2b and 2c are known as the Carr-Purcell-Meiboom-Gill (CPMG) sequence. It is

the most widely used NMR logging sequence. The envelope of the spin-echo signal decays

exponentially with a characteristic time constant, T2, known as the transverse or spin-spin

relaxation (i.e., decay) time.

Formation Evaluation by Tomisin Olapo Page 31

3.0 MODES OF OPERATION OF NMR

Hydrogen (H) has a relatively large magnetic momentum and is also abundant in rocks. By

tuning NMR logging tools to the magnetic resonance frequency of hydrogen, the signal of the

precessing nuclei is maximized and measured.

The decay of the NMR signal (transverse relaxation time, or T2-time), i.e. the response of the

hydrogen nuclei to an outside external magnetic field, and the total signal amplitude are the

measurements exploited with NMRlogging tools.

The measurement sequence starts with proton alignment, spin-tipping and precession,

followed by repeated dephasing and refocusing.

The relaxation time T2 depends on the size of the pore-space and is thus a direct measure of

porosity. The advantage of the NMR technique is that the porosity measurement is

independent of lithology (not like density-porosity) and is carried out without radioactive

sources.

Spin-tipping and precession:

The next step in the measurement sequence is spin-tipping, i.e. the aligned protons are

tippedthrough applying an oscillating magnetic field B1.The frequency of B1is set to the so-

called Larmorfrequency, a specific frequency for each type of nucleus. Hydrogen has a

Larmorfrequency of 2.3 MHz in a magnetic field of 550 Gauss. The magnitude of the tip-angle is

Fig 4: Shows the alignment of the

proton field in 3-Dimension

Formation Evaluation by Tomisin Olapo Page 32

a function of the magnetic field strength B1and for how long it is switched on. To obtain a tip-

angle of 90 degrees of hydrogen you need a field of 4 gauss switched on for 16 micro-seconds.

Dephasing (FID)

First the protons will precess around the new direction of B1in unison. While doing so, they

generate a small magnetic field at the Larmorfrequency, which is measured by an antenna

inside the NMR tool.

However, B0is not perfectly homogenous and the protons do not all precess exactly at the same

frequency. Gradually they lose synchronization (dephasing) and the decaying signal is

measured. The decay time is called T2* (the asterisk indicates that this is not a formation

property) and is comparable to the span of the tipping pulse length. This decay signal is also

referred to as free induction decay (FID).

Refocusing, spin-echoes:

The CPMG pulse sequenceThe dephasing caused by in homogeneities of B0 is (somewhat)

reversible. The protons (all precessing at a slightly different frequency) can be refocused by a

new pulse, which is180 degrees oriented to the original spin-tipping pulse and also twice as

long. As the protons rephase, they generate a new signal in the antenna –called a spin-echo.

The spin echo decays again on the rate of the FID. However, the 180-degree pulses are applied

repeatedly –typically several hundred times within a single NMR measurement. The usual

procedure is to apply 180-degree pulses in an evenly spaced train, as close together as possible.

The entire pulse sequence (90ºplus a long series of 180ºpulses) is called a CPMG sequence,

named after their inventors:Carr, Purcell, Mayboomand Gill.

Formation Evaluation by Tomisin Olapo Page 33

4.0 APPLICATIONS OF NMR

The Applications of NMR are listed below:

Porosity

Reservoir quality

Permeability

Thin-bed analysis

Hydrocarbon identification

The new tool brings the following new answers to the NMR arsenal:

Hydrocarbon characterization (oil viscosity)

Near-wellbore fluid saturation

Potential for wettability1 and pore geometry2 evaluation

Formation Evaluation by Tomisin Olapo Page 34

5.0 REFERENCES

Brown, R.J.S. et al.: “The History of NMR Well Logging,” Concepts in Magnetic Resonance

Logging, 13, No. 6, 340.

De Pavia, L. et al.: “A Next-Generation Wireline NMR Logging Tool,” paper SPE 84482 presented

at the 2003 SPE Annual Technical Conference and Exhibition, Denver, 5–8 October.

Freedman, R. and Heaton,: “Fluid Characterization Using Nuclear Magnetic Resonance

Logging,” Petrophysics (May/June 2004) 45, No. 3, 241.

Freedman, R. et al.: “Measurement of Total NMR Porosity Adds New Value to NMR Logging,”

paper OO presented at the 1997 Annual Meeting of the Soc. of Professional Well Log Analysts,

Houston, 15–18 June.

Prammer, M. et al.: “Measurements of Clay-Bound Water and Total Porosity by Magnetic

Resonance Logging,” paper SPE 36522 presented at the 1996 SPE Annual Technical Conference

and Exhibition, Denver, 6–9 October.

McKeon, D. et al.: “An Improved NMR Tool Design for Faster Logging,” paper CC presented at

the 1999 Annual Meeting of the Soc. of Professional Well Log Analysts, Oslo, Norway, 30 May–3

June.

Allen, D. et al.: “How to Use Borehole Nuclear Magnetic Resonance,” Schlumberger Oilfield

Review (Summer 1997) 9, No. 2, 34.

Ramakrishan, T.S. et al.: “Forward Models for Nuclear Magnetic Resonance in Carbonates,”

The Log Analyst (1999) 40, No. 4, 260.

Freedman, R. et al.: “A New NMR Method of Fluid Characterization in Reservoir Rocks:

Experimental Confirmation and Simulation Results,” paper SPE 75325 SPEJ (December 2001)

452.

Ahr, W.M. et al.: “Confronting the Carbonate Conundrum,” Schlumberger Oilfield Review

(Spring 2005) 17, No. 1, 18.

Freedman, R. et al.: “Combining NMR and Density Logs for Petrophysical Evaluation in Gas-

Bearing Formations,” paper II presentedat the 1998 Annual Meeting of the Soc. of Professional

Well LogAnalysts, Keystone, Colorado, 26–29 May.

Akkurt, R. et al.: “NMR Logging of Natural Gas Reservoirs,” The LogAnalyst (1996) 37, No. 6, 33.

Formation Evaluation by Tomisin Olapo Page 35

Hürlimann, M.D. et al.: “Diffusion-Editing: New NMR Measurements of Saturation and Pore

Geometry,” paper FFF presented at the 2002 Annual Meeting of the Soc. of Professional Well

Log Analysts, Oiso, Japan, 2–5 June.

Heaton, N.J. et al.: “Saturation and Viscosity from Multidimensional Nuclear Magnetic

Resonance Logging,” paper SPE 90564 presented at the 2004 SPE Annual Technical Conference

and Exhibition, Houston, 26–29 September.

Guru, U. et al.: “Low-Resistivity Pay Evaluation Using Multidimensional and High Resolution

Magnetic Resonance Profiling,” paper OOO presented at the 2005 Annual Meeting of the Soc.

of Petrophysicists and Well Log Analysts, New Orleans, June 26–29.

Freedman, R. et al.: “Wettability, Saturation, and Viscosity From NMR Measurements,” paper

SPE 87340, SPEJ (December 2003) 317.

Flaum, M., Chen, J., and Hirasaki, G.J.: “NMR Diffusion-Editing for DT2 Maps: Application to

Recognition of Wettability Change,” Petrophysics (April 2005) 46, No. 2, 113.

Freed, D.E., Durcaw, L., and Song, Y.Q.: “Scaling Laws for Diffusion Coefficients in Mixtures of

Alkanes,” Physical Review Letters (2005) 94, 067602, 1. JPT

http://www.encyclo.co.uk/visitor-contrib

http://eps.mcgill.ca/~courses/c550/borehole-lecture10-NMR.pdf