Well Test - Self learning Module - Pet Eng

8/13/2019 Well Test - Self learning Module - Pet Eng

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This document is part of a self learning programme designed for new

petroleum engineers with limited experience of well testing operations.

Experienced engineers, occasionally involved with such operations, mayalso find the module useful.

This module contains a step by step guide on how to approach the planning,

witnessing, interpretation and reporting of a well test. A case study is

provided which is used as an example at each step in the guide. Thedocument is intended to double as a quick reference guide for wellsite or

office based staff who have followed the Well Testing self learning

programme.

1. Uses of well testing What, in general, can be achievedby well testing?

2. Planning a well test

2.1 Setting the test objectives What do you want to know, and canyou justify the cost of finding out?

2.2 Designing the well test procedure What method will you use to find out?2.3 Assuring sufficient data quality What tools does the method require?

3. Witnessing operations What is measured?

Is the data quality sufficient?

4. Analysing the well test Turning data into information

WELL TESTING

Self Learning Module



WELL TESTING

TRACS INTERNATIONAL

Section 1 Uses of Well Testing

Section 2 Planning a Well Test

2.1 Setting the Objectives

2.2 Designing the Well Test Procedure

2.3 Assuring Sufficient Data Quality

Section 3 Witnessing Operations

3.1 The Production Test Proposal and

Programme Documents

3.2 Running the Test String

3.3 Sequence of Events: Data Gathering and

Recording and On-site Quality Control

Section 4 Analysing the Well Test

4.1 Analysis Principles

4.2 Analysis Techniques

4.3 Special Test Types

References

Section 5 Answers to Worked Exercises

Section 6 Gas Well Test Example

Section 7 Equipment Session

Section 8 Competency Assessment

(Mentor Guidelines)

CONTENTS



1 - 1

WELL TESTING

TRACS INTERNATIONAL Uses of Well Testing

1. USES OF WELL TESTING

All well testing is based on the principle of flowing a well and measuring the response of a

number of key parameters, most notably pressure and rate with time. Information can be gainedin three areas:-

Reservoir Description

– Mathematical models can be used to relate flow rate changes and time dependent pressure

responses to surrounding reservoir properties (permeability-thickness, boundaries,

heterogeneity) and the connection efficiency of the well to the reservoir (skin factors).

– Flow rate & pressure drawdown can be used to measure well productivity index

(production rate per unit of pressure drawdown).

– The measurement of fluid flow from different layers will allow an estimate of permeabilitycontrasts between layers.

– Mathematical models can also be used to relate time dependent pressure responses from

surrounding wells to measure the reservoir transmissibility between wells.

– The minimum connected hydrocarbon volume to the well can be determined from the

decline rate in reservoir pressure during a well test.

– Initial reservoir pressure & temperature can be measured.

Fluid Properties

– Fluid samples will allow a measurement of basic fluid properties such as composition,

formation volume factor (Bo), gas-oil ratio (GOR) & viscosity (µ

o).

– Fluid samples will also allow measurement of fluid contaminants such as H2S, CO

2,

asphaltenes, wax, mercury, etc. Representative measurements can often only be made at

the wellsite due to degradation of samples over time.

– Fluid samples from different sands will determine fluid variations with depth, area or

zone and in particular can be used to define fluid contacts.

Wellbore Performance

– Multi-rate tests can be used to measure rate-dependent downhole and surface pressures.This will allow a wellbore hydraulics model to be calibrated and hence optimise well &

completion design.

– Multi-rate tests can be used to measure rate dependent skin factors and hence optimise

well perforation & completion design.

– Multi-rate tests can also be used to measure rate dependent problems such as sand

production or water/gas coning.

Many different types of well test can be performed, and the choice depends wholly on the

information which is being sought. Being clear about the objectives of the test is paramount indeciding the type of test to carry out. Figure 1.1 shows some of the common types of test

performed.



1 - 2

WELL TESTING


Figure 1.1

drawdown build-up

P

q

P

q

P

Pressure Drawdown Pressure Build-up

timetimeIndicates = kh, s, PI kh, s, depletion, Pi, p

q

q4P

P

dPdt

Multi-rate Drawdown Reservoir Limit Test

Interference Test

Pulse Test

timetime

timetime

Indicates = kh, rate dependent skin, PI kh, s, connected volume

= const

Active WellObservation Well

Active Well Observation Well

Indicates transmissibility ( kh )µ

Indicates transmissibility ( kh ) cmµ

q1

q2

q3

P

P

q

P

q

P



1 - 3

WELL TESTING


A pressure drawdown survey, in which the flowing bottom hole pressure is measured while

the well is flowing, is a primary method of measuring productivity index (PI). Establishing a

stable rate over a long period can be difficult, creating some uncertainty in analysis.

PI = production rate (bbl/d)

pressure drawdown (psi)

Pressure build-up surveys measure the bottom hole pressure response during the shut in period

which follows a pressure drawdown. This is useful for measuring reservoir properties and near

well effects such as skin. In this test, the flowrate is known (zero).

Multi-rate tests are used to determine rate-dependent properties such as skin, and are commonin gas well testing. By definition this is a form of pressure drawdown test, but is usually followed

by a pressure build-up.

Reservoir limit tests are designed to establish the hydrocarbon volume connected to the well.

In the example shown, the flowrate is constant and once the limit of the reservoir has beenestablished the pressure drops linearly with time, indicating that the reservoir is fully bounded.

This “semi steady state” response can be used to estimate the connected volume of fluid.

An interference test between two wells is used to estimate the transmissibility (kh/ µ) of the

formation in the interval between the wells. A pressure change is created at the active well byshutting in or (in the example) opening up the well, and a pressure gauge in the closed-in

observation well awaits a pressure response, the arrival time of which can be used to estimate

transmissibility.

A pulse test is a version of the interference test, but attempts to provide enough information toallow the interpreter to eliminate the effects of noise and gauge drift in pressures (to which the

interference test is prone) as measured at the observation well.



2 - 1

WELL TESTING

TRACS INTERNATIONAL Planning a Well Test

2. PLANNING A WELL TEST

Well testing represents a major source of data to engineers and geoscientists investigating the

potential economic viability of hydrocarbon accumulations. However, well tests are expensiveand should only be performed if the information required

a) improves the value of the project by more than the cost of the test and

b) cannot be adequately acquired more cheaply by an alternative method.

The planning stage is important in determining the value of the welltest, defining clear objectives

for the test, selecting the test type, specifying the equipment required and the procedures to be

followed, and indicating what actions should be taken on the rig site if the observed response

differs from that anticipated. It is not impossible to spend $10 million on a well test in the NorthSea, which could exceed the cost of drilling the hole, so significant effort at the justification and

planning stage is warranted.

During Section 2, you will be planning a well test for an offshore appraisal well.

2.1 SETTING THE TEST OBJECTIVES

The following summarises the data available on a discovery to date. Three wells have been

drilled into Brent sands in the main block of a discovery; two have tested oil (±31°API,

30 sm3 /stm3) and the third logged only water bearing reservoir. The STOIIP in the main block isapproximately 100 MMstb. The two oil bearing wells have been completed and suspended at the

subsea wellhead, awaiting a tieback to a nearby production facility.

Figure 2.1 Ben Mor Discovery

Top Brent sands map, indicating discovery and possible northern block accumulation

Depths in feet tvss

'A'

8 4 5 0

8 4 0 0 8 5 0 0

8 6 0 0

8 5 0 0

8 5 0 0

8 7 0 0

ODT 8780

1 km

'A'N

B-3

B-2

B-1

B-4



2 - 2

WELL TESTING


A 3-D seismic section is available across the area, and shows that there is potential for an additional

accumulation in a northern block, which is the target of appraisal well B-4.

Figure 2.2 Seismic cross section through A-A’

The well proposal for the drilling of well B-4 includes the proposal to core the well once there

are hydrocarbon shows in the mud returns. Coring will continue until the hydrocarbon bearing

interval is fully cored. A full open hole logging suite will be run, including RFT pressure andfluid sampling. The drilling proposal also requires an outline production test proposal to ensure

that the necessary equipment can be made available in time if the well is found to be hydrocarbon

bearing.

2.5 2.5

A'A

A'A

Seismic Line 1973 Vintage Unmigrated

84 Vintage 3-D Migrated

2.5 2.5

A'A

A'ASeismic Line

SOUTH NORTHBen Mor-4 (projected)

0 1 2 km

T W

T ( S e c s )

'X''TB''MNS''BB'



2 - 3

WELL TESTING


BEN MOR DISCOVERY EXERCISE 1: Test Objectives

Before trying to set the test objectives, you should be aware of the overall objectives of the well.

These were to:-

• assess the presence and nature of hydrocarbons in the northern block

• determine whether the sands (if present and hydrocarbon bearing) are commercially

productive

• corroborate the geological and geophysical model of the northern block to assist withfuture development of the northern block

• determine whether the northern block is in pressure communication with the main block

With the well objectives in mind, list the objectives of the well test in the table below, in order of importance, and indicate what other forms of data could be used to achieve the objective.

Test Objectives Alternative data sources

1.

2.

3.

4.

5.

What are the drawbacks, if any, of the alternative data sources?

When you have thought carefully about the objectives and filled in your answer, look at the

suggestion at the back of the guide.

The objective of well testing changes over the life cycle of a field, and testing is generally moredifficult to justify as more information is available on the field. In the Ben Mor example, theoutcome of the production test is likely to influence whether further appraisal or development is

warranted or whether the northern block prospect is included in the main field development

plan. The result of the test may have very significant impact on the overall value of the project,

and decision making theory should be applied to determine the value of the information gained

from the test.



2 - 4

WELL TESTING


The following table indicates the typical objectives of well testing using bottom hole pressure

(BHP) surveys during the field life cycle.

Activity Exploration Appraisal Early Production Late Production

Objective Are there HC What types of Completion Understand

hydrocarbons hydrocarbons? efficiency productivityin the reservoir? Changes in anomalies

Productivity productivity

Resevoir After

pressure stimulation to

response to check PIproduction improvement

Type of test DST or Production Production Production

production test test test test

Frequency Once Once Once By exception

A drill stem test (DST) is a production test in which a full production string is not run as part of

a well completion, but a temporary test string (often drillpipe) is used. This avoids the cost of lining the hole and running and setting a test string with a packer. DST packers may be set in

open hole or in cased hole. Specific intervals can be tested by use of a straddle packer.

2.2 DESIGNING THE WELL TEST PROCEDURE

2.2.1 Test type

Section 1 summarised the main types of well test and the information which they yield. The

selection of the test type clearly depends upon the objectives of the test. Given the objectives of the test of well B-4 in our example, the most appropriate test type will be a pressure drawdown

and build-up, with fluid sampling being part of the test procedure. Whether we take surface or

subsurface samples will be debated later in Section 2.2.5.

Ben Mor Northern Block Test Type: Drawdown and Build-up

In general, single rate change tests are used to measure reservoir properties. For a pressuredrawdown test this means flowing at a single stable rate for a period of time. However, it can be

difficult to maintain a constant rate due to fluctuations through the wellbore and surface equipment.

The rate during a build-up period is obviously zero, but the analysis is simpler if the preceding

drawdown has been carried out at a single constant rate. Build-up periods are generally considered

more useful for analysis as the flowrate is constant.

Multi-rate test are typically used to measure rate dependent properties such as some skin

effects and wellbore effects, and are more common in gas wells where skin due to turbulent flowaround the wellbore is a function of the flowrate. Skin is discussed in detail in Section 4.1.2.



2 - 5

WELL TESTING


A basic well test sequence is shown below indicating some of the different requirements from

each part of the test. This test does include a multi-rate test, which would be less common in oil

wells than gas wells:

Figure 2.3 Basic well test sequence

Period 1 Clean-up• remove perforating debris and completion fluid from the wellbore

• determine basic fluid properties and action any changes to test procedures

Period 2 Initial build-up• measure initial reservoir pressure & temperature

• restore pressure equilibrium before starting main test

Period 3 Main drawdown• measure well productivity index

• a preliminary estimate of reservoir properties can be made from pressure

analysis techniques provided rate changes are not too significant

• measure contribution to flow from different sands to determine permeability

contrasts between layers (this would require the use of a multilayer test or aPLT tool)

• take surface fluid samples & measure fluid contaminants

Period 4 Main build-up• pressure analysis techniques are used to interpret the surrounding reservoir

properties (permeability, boundaries, heterogeneity) and the connection

efficiency of the well to the reservoir (skin factors)

• final reservoir pressure may be observed to check for reservoir depletion

Period 5 Additional flow period

• take downhole fluid samples to measure definitive fluid properties - see

section 2.2.5 for discussion of subsurface vs. surface sampling

Period 6 to n Additional flow periods at different rates

• determine flow rate dependency of skin factor, sand production, and

calibrate well hydraulics model

1 2 3 4 5 6 n

4 rates (25, 50, 75, 100%)

Time

Clean-upMax. flowrate

(not necessarily maximum potential)

Start of Test End of Test

P r o d u c t i o n R a t e



2 - 6

WELL TESTING


2.2.1Test interval

Once the open hole logs are available and a “quick look” interpretation has been made, an

office-based operations meeting is usually called between the subsurface and operations team to

decide on the exact interval to test. In a single string venture, with poor communications to thebase, this decision may need to be taken on the wellsite. Again, reference to the test objectives is

essential to the selection of test interval.

BEN MOR WELL B-4 EXERCISE 2: Test Interval

Below is a quick look interpretation of the open hole logs from well Ben Mor-4. The followingannotations are important:

Annotation Meaning

CAL caliper log

GR gamma ray log

TRCN compensated neutron log

FDC formation density log

DILD dual induction log (deep)

por porosity (fraction)

hys hydrocarbon saturation (fraction)

perm permeability (mD)

TAR top of Tarbert formation

NU top of Upper Ness formation

NM top of Mid Ness Shale formation

ET top of Etive formation

RA top of Rannoch formation

DG top of Dunlin Group



2 - 7

WELL TESTING


Figure 2.4 Ben Mor Well B-4 - Openhole Log Results

CAL_01R

IN

GR_01R

GAPI

6 16

0 150

TRCN_01R FRAC

FDC_01R

G/C3

-6

2.8

54

1.8

DILD_01R

OHMM1 100

POR HYS PERM

10000.110.40

TAR

NU

NM

ET

RA

DG

13300

13400

13500

13600

13700

13800

13900

14000

14100

14200

"D"

F



2 - 8

WELL TESTING


You should assume that an open hole DST is not permissible for safety reasons, and therefore

the hole will be cased before testing. Based on the logs, is the well worth testing, can you

achieve the stated objectives with a well test, and if so, where would you propose to perforate

the well prior to testing? Mark the interval on the log.

What other sources of information should you be using to identify whether the hydrocarbons

indicated on the logs are oil or gas?

When you have worked this through, check with the answer at the back of the guide.

2.2.3 Flow and shut-in durations

The length of flow and shut-in periods are a compromise between the quantity of information

required and the expense of performing the test. Longer flow & shut-in periods will provide

information on the reservoir further from the wellbore. The time taken to first observe a reservoir

heterogeneity at distance r from the wellbore is given for drawdown tests as:

T ø c r

k

t = µ

1191 42

.

The estimate of permeability will need to be taken from core measurements. The openhole log

interpretation estimates a permeability based on an empirical porosity -permeability relationship

from the region. In addition to this source of permeability estimate the core taken in the well hasbeen “hot shotted” to town and quicklook permeability measurements indicate an average

permeability of 1500 mD over the reservoir interval.

For a build-up, calculating the time taken is more complex depending in part on the length of the

preceding flow period.

Assuming a radial inflow model, information gained around the well is a bulk average of all the

reservoir effects. The further that information is gained away from the well the larger that averaging

process. This can mean that extended test times generally result in diminishing returns in

delineating specific reservoir parameters at a large distance from the well.

Early time data is often dominated by wellbore storage effects (see section 4.1.3), which make

interpretation very difficult if not impossible. Consequently flow & shut-in periods should be of sufficient length to pass this period. Equations defining the end of wellbore storage are given in

section 4.1.3.

At the other extreme, in reservoir limit testing, it may be necessary to flow for weeks or months

to generate a measurable depletion of pressure. As a rule of thumb, a 50 psi depletion is significant

and sufficient to estimate the connected volume. From an initial estimate of the connected volume,

material balance calculations can be made to determine the produced volume required to createsuch a pressure drop. Again with an estimate of the well productivity (or from the early production

data) an estimate of the length of test required can be made. The cost of such a test must be

checked against the value of the information.



2 - 9

WELL TESTING


Well test interpretation techniques depend mostly on establishing transient flow (covered later

in Section 4.1.1), and derivatives on type curves (Section 4.2.3) indicate when this flow regime

commences for a given reservoir type (eg homogeneous, fractured). This method can be used to

estimate the minimum time required for the flow and build-up periods.

In general the time taken to observe all the required reservoir properties surrounding a well is

best modelled using the design feature in a computerised well test package. An expected reservoir

model should be constructed in liaison with the field geologist and used within the well test

package to anticipate the required test duration.

Although it is impossible to give a unique time for the periods, typical drawdown and build-up

periods are between 6-12 hours and 12-24 hours respectively.

BEN MOR WELL B-4 EXERCISE 3: Test duration

In view of the test objectives, are there any special requirements for the test duration. What doyou recommend for the flow and build-up periods? Check your ideas with the solution at the

back of the guide.

2.2.4 Flow rate

The size of flow rate has little bearing on the mathematics of well test analysis. The rate should

however be sufficient to maintain stable flow. A wellbore hydraulics package should be used to

design tubing sizes and minimum flow rates to give an acceptable flow regime within the wellbore.

Slugging should be avoided if possible. The maximum possible rate from the well is not necessaryfor the well test analysis, but sometimes in exploration wells there is a requirement to establish

this maximum potential, especially if it is to be used as part of the information provided to apotential purchaser of the block, or in equity discussions.

BEN MOR WELL B-4 EXERCISE 4: Test rate

What physical constraints will determine the flowrate from the well when it is tested. What

instructions will you give the testing crew regarding flowrate?

Constraints on flowrate Instructions to test crew



2 - 10

WELL TESTING


2.2.5 Perforating procedures

Here are some general guidelines on perforating procedures.

• intervals should be perforated bottom up to avoid wireline passes across perforated intervalsand thus reduce the potential for stuck tools.

• perforating is generally performed underbalanced in order to clean debris out of the

perforated channels. This can be optimised by perforating all intervals together through

the use of tubing conveyed perforating (TCP) guns.

• perforating can also be performed overpressured in order to fracture the reservoir as the

well is perforated. This can help to increase well productivity, but is a special application.

• as soon as the first perforating run has taken place a clean up period should be considered

to displace wellbore completion fluid from the well and avoid it slumping into the formation

and potentially causing wellbore damage.• perforation gun type and ratings should be designed to maximise well productivity.

Perforating efficiency packages are available.

• Maximum perforating gun length will determine the number of runs required in the hole.Tool rig-up conditions and gun type should be designed to reduce rig time.

2.2.6 Sampling: pressure, rate, time and fluids

Time, rate and pressure are the key measurements required for well test analysis, and this data

set is often referred to as the TRP data. It is essential to specify in the test proposal the frequencyand location of

• pressure sampling, gauge types

• flowrate measurements

• fluid samples

The following schematic shows the typical points for monitoring these parameters. Because the

quality of this data is so important to the successful interpretation of the test, the details of gauge

selection and monitoring requirements will be specifically addressed in Section 2.3.



2 - 11

WELL TESTING


Figure 2.5 Typical locations for pressure and rate monitoring, and fluid sampling

FTHPFTHT

Samples

Chem. Inj.

DataHeader

Gas flare

Oil burner

Psep, Tsep

Gas meter

Psep, Tsep

Test Tank (for low flowrates)

Heater

Liquidmeter

D i v e r t e r m a n i f o l d

Transfer Pump

Wireline

Test string

Downholepressuretemp. gauge

Casing

Surfacereadout &

T,P

ChristmasTree

ChokeManifold

Test Separator



2 - 12

WELL TESTING


The exact set-up will depend upon the type of location (eg land, floater or production platform)

but the main components will remain the same. The downhole pressure gauge can record pressure

and time data downhole and can display this information in real time at surface using surface

read out (SRO) if required. The data header provides ports for monitoring flowing tubing head

pressure (FTHP), temperature (FTHT), taking flowline samples, monitoring sand production,and performing chemical injection. The choke manifold controls fluid flow, and is used to

establish stable flow conditions and to shut the well in. A heat exchanger may be required to

prevent hydrate formation (gas testing) or to allow viscous oil to flow at surface conditions. The

test separator (typically a three phase horizontal design) not only separates the three phases

(oil, water, gas) but also measures the flowrate of each stream using flowmeters on each of theoutlet lines. It is important to record the separator temperature and pressure to allow the rates

measured to be corrected to standard conditions (typically 60°F and 1 bar). A test tank may be

required to measure liquid flow rates if the FTHP is insufficient to allow the use of the three

phase separator, and may be used as a check on the three phase separator measurements. The

diverter manifold directs oil and gas to the appropriate burners, depending on the current winddirection. To keep the heat away from the installation, flare booms are used, and oil burners

inject compressed air and water through nozzles to create efficient combustion and to cool the

flame.

Fluid samples can be taken down-hole or at surface, the relative merits of which will be discussedin Section 2.3.

2.2.7 The test string

The test string refers to the subsurface equipment run below the well head. The configuration

will depend upon the type of well, the installation, and the type of test. The simplest test string isthat required for a DST (drill stem test) in which a temporary test string is run in the hole and set

using a retrievable packer. The following diagram shows different versions of the DST.

gaugecarrier

Open HoleOpen Hole

Zonal IsolationCased Hole

Figure 2.6 DST Configurations



2 - 13

WELL TESTING


The concerns with a DST are as follows: will the inflatable packer seal, is the formation strong

enough at the casing shoe to withstand gas influx, will the borehole remain stable throughout the

duration of the test (all for open hole DSTs), will the tubing joints have sufficient integrity to

stop gas leaks around the joints or to withstand the corrosion of fluids such as H2S? The latter

can be managed by specifying sufficient quality tubing materials and gas tight connections, butthe packer integrity and borehole stability may be of sufficient concern that the company policy

is not to run open hole DSTs. You should check what your company policy on DSTs is.

At the other extreme from a DST, the following diagram shows a full production test string for

a well test of a cased and lined well.



2 - 14

WELL TESTING


Figure 2.7 Full test string for a cased and lined well

Note in this test string design that tubing conveyed perforating (TCP) guns are run on the bottomof the test string to reduce the need for wireline perforation, and allow underbalanced perforat-

ing. Note also the position of the gauge carrier relative to the TCP guns which will be at the

reservoir depth.

radioactive tag

3120m AHBDF

3m of sealsstabbed into

seal bore

3286m AHBDF

Perforation interval

3333m AHBDF

31 / 2",15.8, L80 Tubing 114.3 63.1

Short Valve 127.0 61.0

3 Joints 31 / 2" Tubing 114.3 63.1

Short Valve 127.0 61.0

1 Joint 31 / 2" Tubing 114.3 63.1

2 x Gauge Carriers 134.1 61.0

1 Joint 31 / 2" Tubing 114.3 63.1

RN Nipple 114.3 58.7

Locator 106.3

Seal Assembly (80-40 LE-22) 101.6 63.1(Seal Length 30ft)

X - over 31 / 2" x 27 / 8" VAM 100.0 63.0

27 / 8", 6.4 ,L80 Tubing 81.2 62.0

Perforated Pup Joint 81.2 62.0

3 Joints 27 / 8" Tubing 81.2 62.0

XN Nipple 81.2 57.1

Debris Circulating Sub 81.0 50.5

1 Joint 27 / 8" Tubing 81.2 62.0

Firing Head 77.8

TCP Guns 73.0

OD IDmm mm

Test String Details



2 - 15

WELL TESTING


The test string should be designed to acquire sufficient data to meet the objectives of the test

with the simplest equipment to run and operate (minimum wireline requirement), in a safe manner.

Some of the constraints which will affect the test string design include

• the expected flowrate

• the test pressures and temperatures

• sufficient tubing size to run required wireline tools (eg a 2 1/8" through tubing perforating

gun)

• the ability to carry sufficient pressure and temperature recorders

• the ability to control the well safely

• the ability to withstand corrosive fluids (eg CO2, H

2S) - in new areas where the presence of

is uncertain the string will normally be for sour service

A typical test string is 3 1/2" tubing for a standard well test, with 5" tubing for high rate tests.Remember that the rate has little material effect on the well test interpretation, unless one objective

is to establish the maximum potential of the well.

2.2.8 Surface Equipment

The specific surface equipment used will depend upon the location (eg floater, production

platform, land operations) and the type of fluid to be tested (gas, oil), but the principal elements

will remain the same. The equipment items are typically skid mounted and will be tested in the

workshop prior to being assembled on the test site. The following diagram (provided by theExpro Group) shows the typical layout of offshore testing equipment, in this case with a subseatest tree for testing a subsea well.

In the equipment session at the end of the module you will arranging your own opportunity to

see this equipment in the workshop being prepared for a well test.

2.2.9 Artificial lift and Stimulation

In low productivity or low pressure reservoirs artificial lift in the form of gas lift (nitrogen with

coiled tubing) or electric submersible pumps (ESPs) may need to be considered in order to

generate a stable flow rate. Stimulation in the form of acidisation or fracturing may be requiredto get a highly damaged well or a low productivity well to flow.

Because of the long lead times required to get stimulation equipment in place, if the need is

suspected, then procedures should be built into the well test programme with equipment on

standby.

It can be frustrating and expensive if we define a hydrocarbon column from the logs but are not

able to test the well due to low productivity for the lack of stimulation equipment. For example,

many Southern North Sea gas wells can only be made commercial after fracturing the tight

sands. Testing an exploration or appraisal well to identify whether the production rates willmake a commercially attractive development may be a key step in justifying further activity.



2 -1 6

T R A C S I NT E R NA T

I O NA L

P l a nni n g a W e l l T e s t

F i g ur e 2 . 8 W e l l T e

s t i n gL a y o u t

3 Phase Test Separator

RemoteESD Stations

RemoteESD Stations

RemoteESD Statio

Heat Exch

Burner

Burner Booms

Propane Racks

Air Compressors

SurfaceSafety ValveHyd. Contro

Propane Racks

Air Compressors

Burner Heads

Burner Booms

Gas DiverterManifold

TransferPump

SurgeTank

Oil DiverterManifold

Relief Valve Choke Manifold

Gas Line

Oil Line

Water Line

Air Line



2 - 17

WELL TESTING


2.3 ASSURING SUFFICIENT DATA QUALITY

This section addresses the tools required to take adequate time, rate pressure and fluid samples

to meet the objectives of the test.

2.3.1 Pressure measurement

Pressure measurement can be made at surface and downhole. For production tests downhole

gauges are invariably run, and these are of three main types:

• mechanical gauges (eg Amerada type)

• electronic memory gauges

• electronic surface readout (SRO) gauges

Electronic gauges have now replaced mechanical gauges for most downhole applications. There

are two main categories of electronic gauge; strain gauge and quartz crystal gauge. Gauge selection

is based on the criteria listed in the following table, plus price. The following table gives themanufacturers specifications for a typical strain gauge and quartz crystal gauge (in this example

Geoservices gauges):

Gauge Name MSG-S -20 MQG - 20

Gauge type strain quartz

Pressure

range (psi) 0 - 20000 0 - 20000

accuracy (psi) ± 4 ± 4

resolution (psi) 0.6 0.02

Temperature range (°F) 32 - 347 32 - 347

accuracy (°F) 1.08 0.36

resolution (°F) 1.08 0.036

memory type EEPROM (electronically) EEPROM

memory capacity 32768 (temp + press) 32768 press, 8192 temp

O.D. / length (in) 1 1/4 / 56.3 1 11/16 / 56.3

In general, the gauge accuracy, resolution, robustness for the reservoir conditions and price areprime considerations in gauge selection. Resolution refers to how small a difference in pressure

the gauge can detect.



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WELL TESTING


BEN MOR WELL B-4 EXERCISE 5 : RFT gauge resolution

An RFT tool has been run in well B-4 and has logged pressures across the Brent reservoir

interval, including the lowest oil bearing sand in the Upper Ness (13630 - 13660 ft ahbdf). If thewell B-4 is deviated through the reservoir at 61°, the true vertical thickness of this interval is

15 ft. The RFT tool was run across this interval to determine the fluid gradient in order toconfirm the open hole log interpretation that that the interval is oil bearing, in which case the oil

gradient would be around 0.3 psi/ft (water would be around 0.45 psi/ft).

Assume you took pressure samples at the top and the base of this interval. The following shows

(schematically) the true pressures at these depths (which you do not know). In order to establishthe fluid gradient, which characteristic of the pressure gauge is important; accuracy or resolution?

Suppose you selected a strain gauge for the measurement, with a resolution of 0.6 psi. How

much error could you make in estimating the fluid gradient?

Figure 2.9

As the answer to this exercise demonstrates, the gauge selection depends on the performance

required to meet the test objectives. For example, in an interference test, the pressure differences

which the observation well is expected to detect are very small (often less than 1 psi), in which

case the highest resolution gauges are necessary.

At least two pressure gauges should be run in any well test to avoid problems from gauge failure

or drift. Pressure gauge drift can be checked in most welltest packages by performing differencecalculations between two independent gauges. The absolute pressure difference should be constant

and explainable. The following plot is the RFT data for Ben Mor-4

Pressure (psi)

Depth(ft tvss)

15 ft



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WELL TESTING


Figure 2.10 Ben Mor-4 RFT Plot

Downhole shut-in

If the reservoir description near the well bore is important (eg nearby faulting) then early time

build-up pressure data is important. After a rate change early time reservoir pressure response

can be masked by the compressibility of the fluids within the wellbore. This phenomenon isknown as wellbore storage (see section 4.1.3). A means of avoiding this problem, at least for

pressure build-ups, is to include a valve and pressure gauge in the test string near the perforations

whereby the well is shut in downhole. Consequently there is little volume of wellbore fluid,

below the valve, which can influence the reservoir pressure response.

This system is probably not warranted when fluids remain monophasic within the wellbore, as

liquids have fairly low compressibilities. However, if the reservoir fluid falls below bubble

point and gas is present in the wellbore, then wellbore storage is likely to mask a large proportion

of the reservoir pressure response.

The time taken for wellbore storage effects to end can be modelled by equations or using thedesign feature in a well test package. This should be used to determine the need for downhole

shut in.

-9400

-9300

-9200

-9100

-9000

-8900

-8800

-8700

-8600

-8500

-8400

5200 5250 5300 5350 5400 5450 5500 5550

Pressure psia

D e p t h f t t v s s



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WELL TESTING


BEN MOR WELL B-4 EXERCISE 6 : Downhole shut in

The RFT pressure plot taken in Ben Mor-4 shows the same gradient and absolute pressure as

that in Ben Mor-1. The fluid tested in Ben Mor-1 was an undersaturated oil with a bubble pointof around 600 psi at reservoir temperature. The fluid produced on test in Ben Mor-1 flowed

monophasic to surface.

What is your opinion on the use of downhole shut in for well Ben Mor-4?

Surface pressure gauges

The simplest and cheapest location for a pressure gauge is at surface on the wellhead. Such alocation can however give problems. Firstly, downhole shut-in cannot be used to avoid wellbore

storage. Secondly, the wellbore skin effect is difficult to calculate as the pressure drawdown at

the gauge is not only due to the reservoir but also to rate dependent friction losses in the wellbore.Thirdly, phase segregation of fluids in the wellbore may cause massive pressure fluctuations.

Wellhead gauges are best used in injection wells where the wellbore fluid is monophasic and

incompressible. Even in this case temperature effects can cause problems in interpretation as the

cool injection water is heated up throughout the wellbore.

Downhole gauge location

Pressure gauges are best located downhole close to the reservoir, but there is an extra costcompared to surface location. Gauges can be located above or below the perforations. Advantages

below the perforations are the ability to perform wireline logging, avoiding constricting thewellbore and minimising turbulence. Disadvantages are that perforating debris or sand may fall

onto the tools making them difficult to subsequently retrieve.

In any case, the gauge is unlikely to be located at the reservoir datum depth (which is a specific

reference depth for any one reservoir) and reservoir pressure measured at the gauge will need to

be corrected to the datum depth. This requires knowledge of the fluid gradient inside the wellbore

as well as the reservoir fluid gradient. The former can be determined from the gradient stops

performed when the gauge is run in the hole (Section 3), and the latter from the RFT pressures.

Real time pressure readout (surface read out; SRO)

If downhole pressure gauges are monitored in real time, the test can be interpreted in real time,

giving the opportunity to extend or curtail the test as the opportunity arises. There are large

potential rig time savings in being able to do this. For example, if the test objectives can be metafter 12 hours of build-up, there is no additional benefit of remaining shut in for another 12

hours, even though the well test design specified a 24 hour build-up.

SRO gauges are powered from surface, so the need for battery packs is eliminated, making them

attractive for harsh conditions (HP/HT wells).



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WELL TESTING


SRO is achieved by passing a signal from the downhole gauge to surface using electric cable run

inside the production tubing to surface. Typically a downhole gauge will record the drawdown

data and upon shut in, the wireline will be run into the well to transmit the stored drawdown data

and then transmit the build-up data in real time. If a PLT is run with the welltest, the electrical

wireline provides the real time data. The downside to such operations is the increased potentialfor fishing jobs due to wireline operations.

2.3.2 Rate measurement

Production rates are typically measured at surface through a test separator, using the equipment

shown in Figure 5. A standard offshore 3-phase separator will operate at up to 1500 psig andhandle 80 MMscf/d gas and 10,000 b/d oil. Gas is metered using an orifice plate, while oil is

measured with a positive displacement meter, turbine meter or a vortex meter. It is essential to

record the pressure and temperatures at which the measurements are made so that a conversion

can be made to express the volumes of fluid at standard conditions and at reservoir conditions

where the pressure is measured. The accuracy of such a measurement is approximately +/-10%.Any water content must also be reported to allow the conversion to be made. Oil meters are

calibrated offshore at periods during the test using a gauge tank.

Pressure analysis techniques require downhole flow rates to calculate reservoir properties. Surface

rates therefore need to be converted using an appropriate formation volume factor. Some errormay be generated here as the formation volume factor is not always known for the test separator

conditions on the rig, giving a possible additional error of around +/-10%. A downhole flow rate

can be calculated directly by running a PLT spinner. The accuracy of such a rate is between +/-

2% and +/-10% depending on the spinner type and logging company.

2.3.3 Time measurement

The pressure-time data is recorded by the clock run with the pressure gauge. Traditionally a

mechanical clock was used, but this is now invariably an electronic clock. The sequence of

events at surface is recorded by the test crew in absolute time, and forms part of the report

provided.

2.3.4 Fluid sampling

There are two choices of location for fluid sampling; downhole and at surface. Downhole

samples can be taken with a sampling chamber. The control for opening and closing of thesampler mechanism can be electrical (in which case expensive electrical wireline is required) orclock controlled using wireline, which is cheaper but raises the risk of the clocks not functioning.

Offshore the use of electrically controlled samplers is generally preferred. Surface samples are

taken from the oil and gas lines from the test separator, and then recombined in the appropriate

ratio (the GOR at the time of sampling), creating a “recombination sample”.



WELL TESTING

Downhole sampling of oil wells is generally preferred, especially if the sample can be taken

above the bubble point, so that a single phase is sampled. For gas and gas condensate fields,

surface sampling is the norm. One problem with sampling gas condensate fluids is that at surface

conditions, two phases will have formed as the pressure drops below the dew point. The liquid

tends to run on the wall of any flowline, making representative sampling difficult, and the volumeof liquid to gas is also small which compounds the problem. Mixing the fluids up in at the

wellhead using a nozzle prior to sampling is one method which has been used to try to overcome

this problem.

The general nature of the fluid will be determined from the open hole logs and the RFT tool, andthis will be used to determine the most appropriate type of fluid sample to take. Initial estimates

of fluid properties can be estimated from correlations.

Practical points on sampling

Always ensure that there are sufficient sample containers on board. If it is suspected that H2Smeasurements are required, these need to be performed on board because of the tendency to

absorb into the metal of the sample chamber (unless specialised chambers - eg Teflon lined - are

available).

The integrity of a pressurised sample chamber can be checked for leaks by submerging it inwater after sealing.

BEN MOR WELL B-4 EXERCISE 7 : Fluid sampling

Using the information from the open hole logs and the RFT, recommend a fluid sampling

programme for the test.