Why When and How to Perform IPS Dynamic Studies Original Report

8/2/2019 Why When and How to Perform IPS Dynamic Studies Original Report

1/17

Page 1 of 17

Why, when and how to perform IndustrialPower System dynamic studies

The unfortunate destiny of many expensive Industrial Power Systems (IPS) study reports is to

become worthless desk products while multiple binders of computer printouts collect archive

dust. While studies of electrical power system dynamical behaviour under heavy motor start-

up, fault conditions and re-acceleration have been carried out for many years, there is still

confusion as to why, when and how such studies are of real value in project design.

The purpose of this article is to discuss electrical, computer-based power system dynamic

studies in relation to actual project needs. A case study is presented of a large offshore oil

platform, providing an example of practical application. Dynamic simulations are compared

with measurements made at site of direct-on-line starting of large induction motors. As thedynamic behaviour of the IPS may by far exceed the complexity of the industrial process

which it supplies, it is vital that project management (often mechanical or chemical engineers)

early are made aware of this complexity.

The IPS design processApplication of computer-based dynamic studies in IPS requires close attention to two

important aspects. Firstly, the project phases ranging from the early feasibility studies to the

operation stage of the facility must be understood. Fig. 1 shows a simplified electrical project

lifecycle. The tendency in todays fast track projects is to jump straight from a conceptual

study to procurement of long lead items such as the main power station and other largepackages. It is then difficult to fit in the necessary dynamical analysis to ensure that the power

system will work properly under all operating modes. By the time the complete data to carry

out such studies are available, all the large packages are already on order and any delayed

changes to the Single Line Diagram (SLD) or large equipment becomes very costly.

Secondly, the electrical power system design process itself must be recognized. The design of

an IPS is a repetitive process obviously dependent on the type of project and facility.

Nevertheless, there are some common denominators. In order to arrive at a firm SLD and

facilities for power system operation and control, Fig. 2 shows a typical design process. This

article will not give detailed descriptions of the elements in this diagram, but merely point out

the iterative nature of the process and discuss how to incorporate the dynamic analysis. Theterm dynamic here implies a broader context than just the time simulations on a system

model utilizing a set of first order differential equations, load flow algorithms and applicable

numerical methods. Voltage dynamics involves balancing the available fault level and

equipment withstand capability against sufficient short circuit capacity to start up large loads

without excessive voltage variations. The process of developing the conceptual SLD is

iteration between short circuit and voltage dip calculations. These usually do not require

numerical time simulations and can easily be carried out manually. The selection of voltage

levels also involves equipment considerations such as availability, size, cost, standardization,

etc.

In the conceptual phase there is rarely sufficient data and time to conduct detailed dynamicalsimulations. However, simplified voltage dip calculations for motor starting and other


2/17

Page 2 of 17

dynamic conditions are vital to avoid surprises in the subsequent project phases. Frequency

variations on the other hand, cannot be predicted unless a full dynamic time simulation is

carried out. Still, it is possible to assess the system step loads and include these in the power

station and generator prime mover specifications and requests for bid. If the concept involves

parallel operation of dissimilar power stations, such as diesel engines, gas or steam turbines,possibly with long power lines in between, there is a need for an early dynamical analysis

assessing system stability. The big question is whether major dynamical analysis can be done

while bidding is ongoing. This requires cooperation and supply of technical data from

multiple equipment vendors. Moreover, the power system analyst requires long and specific

experience from other projects with similar type of generators, prime movers and associated

controls.

The pre-engineering phase normally includes a full dynamic study with the objective of

verifying earlier studies and identifying all long lead equipmentparameters and control

system requirements before issuing of purchase orders. For example, an early conceptual

maximum voltage dip calculation for motor starting, would now be superseded by a fulldynamic simulation assessing the entire starting time at given load torque. This verifies motor

and generator thermal capacity requirements (including excitation system) prior to buying.

In detail engineering, the dynamic analysis must be updated, this time with the objective of

setting the relay and control systems parameters. In modern plants, Power Management and

relay protection schemes are highly integrated. Microprocessor controlled multifunction

relays become increasingly complex, and include many of those functions that used to be part

of the Power Management Process Stations. A sound dynamical analysis capturing all of the

relevant normal, special and failure operating modes is extremely important when setting the

power management and protection relays. Relevant disturbances to be dynamically studied

and their counterparts in relay and control systems engineering are shown in Table I.

Photo 1 - Oseberg C platform


3/17

Page 3 of 17

Table I System disturbancesDisturbance Relay and control systems engineering counterpart

Loss of generation or distribution systemsections with subsequent load shedding

or load transfer

Design and setting of electrical load shedding or loadtransfer systems which can be based on circuit breaker

trip/status signals, under-frequency, rate of frequency

change (df/dt), electrical power balance, generator prime

mover temperature or combinations of such initiators

AVR / excitation system faults leading to

maximum or loss of excitation output for

one generator

Coordination of generator field failure protection, setting of

bus coupler protection schemes and AVR supervision

systems

Prime mover governor faults Coordination of generator over-current and frequency

protection, setting of bus coupler protection schemes and

power management load sharing supervision

Multiple levels of Process or EmergencyShut Down, which will impose large

load rejection on the power station or

feeding transformers with on-load tap

changers

Coordination of over-frequency and over-voltageprotection as well as engineering of process and emergency

shut down schemes

Temporary voltage disturbances and

subsequent re-acceleration of motors

Design and setting of motor re-acceleration systems

Transition from normal to back-up oremergency power supply with

subsequent re-acceleration

Setting of consumer restart schemes

Short Circuits Coordination of short circuit, under-voltage and frequencyprotection

Figure 1 Electrical project lifecycle

Feasibility

Study

Conceptual

Study

Pre-

engineering

Detail

Engineering

ProcurementManu-

facturing

Follow-on

Engineering

Construction

(Installation)

Completion

Commissioning

(Liven up)

Operation


4/17

Page 4 of 17

Case StudyThe case study comprises a large offshore oil & gas platform. For this existing facility a large

process extension was planned. The platform gas injection capacity had become a bottleneck

in the oil production. Various process options to increase the gas injection capacity were

considered. The electrically most extensive case was to install one new 9.0 MW compressor

package and to upgrade the two existing ones from 6.8 MW to 9 MW. The compressors areall driven by induction motors with DOL (Direct-On-Line) start.

Platform Electrical Power System

The platform electrical power system is outlined in Fig. 3. Main generation consists of two 30

MVA generators at 13.8 kV. . Large induction motors for gas injection, recompression and oil

export are fed from the main 13.8 kV switchboard while medium size motors for seawater lift,

air compressors, etc. are fed from the dedicated 6.0 kV emergency switchboard. Three 1.75

MVA emergency generators (not shown) are connected to the 6.0 kV switchboard. Variable

speed drives for drilling are fed from 660 V switchboards, while platform process auxiliary

motors are fed from 440 V switchboards.

Figure 2 Typical Industrial Power System Design Process

Plant Layout

Production Capacity

Operating Modes

Electrical Codes

LOAD AND SUPPLYPLANNING

SELECTING

SYSTEM NETWORK

HARMONICS

SYSTEM EARTHING

SHORT CIRCUIT AND

DYNAMIC ANALYSIS

SELECTING

VOLTAGE LEVELS

POWER FACTOR

CORRECTION RELAY PROTECTION

AND SELECTIVITY

Specification and Procurement

SURGE PROTECTION

Initial conditions

OPERATION AND CONTROL

IPS must be:Safe

Simple

Maintainable

Flexible

ReliableEconomical

Verifyable

Plant Layout

Production Capacity

Operating Modes

Electrical Codes


SELECTING

SYSTEM NETWORK

HARMONICS

SYSTEM EARTHING

SHORT CIRCUIT AND

DYNAMIC ANALYSIS

SELECTING

VOLTAGE LEVELS

POWER FACTOR


AND SELECTIVITY


SURGE PROTECTION

Initial conditions


IPS must be:Safe

Simple

Maintainable

Flexible

ReliableEconomical

Verifyable

Plant Layout

Production Capacity

Operating Modes

Electrical Codes


SELECTING

SYSTEM NETWORK

HARMONICS

SYSTEM EARTHING

SHORT CIRCUIT AND

DYNAMIC ANALYSIS

SELECTING

VOLTAGE LEVELS

POWER FACTOR


AND SELECTIVITY


SURGE PROTECTION

Initial conditions


IPS must be:Safe

Simple

Maintainable

Flexible

ReliableEconomical

Verifyable


5/17

Page 5 of 17

The main power station consists of Cooper Rolls gas turbines, 24 MW, 4940 rpm with

Woodward governor and Siemens generator, 30 MVA, 1800 rpm, 60 Hz, AVR is Siemens

RG3 15.

New 9 MW Direct-On-Line started induction motorsThe new compressor full load operation was with 65 BAR suction pressure and 8.2 MW

power requirement at 1786 rpm while start duty was with 32 BAR suction pressure. The new

(and existing) compressors are electrically driven by DOL started induction motors. Two

alternative electric motor manufactures were considered during the study. In both cases

motors with 9.0 MW (shaft) power rating, max. starting current of 4.2 p.u. and synchronous

speed of 1790 rpm were applied.

Challenges

The new installation represented a number of challenges. Some of these were:

1. High utilization of the main power stationThe platform electrical load is quite variable due to changing requirements in drilling as

well as process. Peak load with one new 9.0 MW compressor and upgrading the two

existing ones from 6.8 to 9.0 MW was estimated to 46 MW. Gas turbines commonly used

on offshore petrochemical plants generally have a variable output due to variation in

ambient temperature, humidity, fuel quality as well as maintenance and overhaul intervals.

This means that available output from the 24 MW rated engines can vary with several

MWs both ways. However, deterioration of the engines usually implies that available

power is lower than the rated values.

The gas turbine control system applies an exhaust temperature dependent override of the

speed governor. Depending on the setting of this control function and the associated

allowed engine thermal stress, frequency drop will result if the engines are overloaded.

2. Running compressors are sensitive to power frequency variations

Practical experience on the platform had shown that the running injection compressors

driven by induction motors were sensitive to power frequency variations. Excursions rates

exceeding 1 Hz/s represented a risk for the compressors to go into a surging mode with

subsequent Process Shut Down (PSD). The system frequency excursions during start of

one 9.0 MW compressor motor were therefore much more stringently defined by the gas

process itself than the electrical statutory regulations applicable to the facility. The

Norwegian electrical code permits minus 10 % transient frequency variations (6 Hz on a

60 Hz system) with no requirements for rate of change.

3. Generator field winding and excitation system thermal capacity constraints

The high inertia of the combined 9.0 MW induction motor and compressor unit caused

start-up times of about 14 sec. This required further investigations into the thermal

capacity of the generator field winding. This is a common bottleneck for start-up of large

motors with high inertia loads on local generators. The generators have IEC 60034 class F

field winding insulation.


6/17

Page 6 of 17

Figure 3 - Platform electrical power system - Single Line Diagram

Measurements at site and associated calculations

In order to establish the best possible basis for the computer analysis, on-site measurements

were carried out on start-up and stopping of one 6.8 MW induction motor while an identical

motor was already running. In addition, measurements were made on the two main generators

with approximately 9 MW of initial load during the tests/measurements according to table II.

Voltages and currents (instantaneous phase values) were measured according to table III.

Based on these measured values, system frequency and active power for the generators and

the two induction motors were calculated.

Table II Test DescriptionTest no. Description Operating condition

1 Stop of one motor from

running condition- Two generators running (2x31 MVA)

- Load (prior to stop of motor): 23 MW

2 Start-up of one motor - Two generators running (2x31 MVA)

- Load (prior to start-up of motor): 18 MW

3 Stop of one motor from

running condition- Two generators running (2x31 MVA)

- Load (prior to stop of motor): 23 MW

4 Start-up of one motor - Two generators running (2x31 MVA)

- Load (prior to start-up of motor): 18 MW

GT/G A30 MVA

GT/G B30 MVA

Oil exp. 3.0 MWGas recomp. 6.0 MWGas injection: 6.8 MW

13.8 kV

6 kV

New 9 MW gasinjection motor

0.66 kV

0.44 kV


7/17

Page 7 of 17

Table III Tests ArrangementTest Measured Phase

no quantity A B C

1

Bus voltageCurrent, generator A

Current, generator B

Current, motor A

Current, motor B

xx

-

x

-

xx

-

x

-

xx

-

x

-

2

Bus voltage

Current, generator ACurrent, generator B

Current, motor A

Current, motor B

x

x

-

x

-

x

x

-

x

-

x

x

-

x

-

3

Bus voltage

Current, generator A


Current, motor ACurrent, motor B

x

x

x

xx

x

x

-

x-

x

-

-

--

4

Bus voltage

Current, generator A


Current, motor A

Current, motor B

x

x

x

x

x

x

x

-

x

-

x

-

-

-

-

For voltage and current measurements, existing voltage and current

transformers in the 13.8 kV switchboard were used.

A transient recorder Hioki 8826, equipped with a 12 bit A/D

converter, 10 channels, was used.

The sampling frequency for the measurements was 10 kHz.

Calculations based on measurements

The system frequency is calculated on the basis of the voltage measurements from phase A.

The approach is based on finding the distance (in time, t) between two adjacent zero

crossings of the voltage signal (half-period) and calculating the frequency, f, as:

tf

=

21 (1)

The three phase active power (instantaneous value) was calculated based on recorded

instantaneous values of phase voltages (ua, ub, uc) and corresponding phase currents (ia, ib, ic),

according to:

ccbbaamomel iuiuiup ++=, (2)

Equation (2) requires three pairs of corresponding phase voltages and currents. However, due

to a limited number of input channels on the transient recorder, not all tests contained thenecessary number of pairs of voltages and currents (see Table III). Where only two phase


8/17

Page 8 of 17

currents were measured, the third was derived from one of the two measured currents by

shifting it 120 (+ or -).

Where only one current was measured, the second and third were derived from the one

measured by shifting them 120 and 240 respectively.

It is reasonable to believe that the error introduced by this approach is relatively small, except

for the initial part of the transient period.

Measurements - comments and assessments

The largest negative voltage deviation measured during motor start-up (test 4) was 9.5 %.

The largest positive voltage deviation (over-swing) was measured during test 2 at +4.3%. This

over-swing may be explained by the characteristics of the generator AVR and its brushless

excitation.

The largest frequency drop was measured during motor start-up in test 2 at -1.4% (see Fig. 8).

The largest frequency increase was measured during motor stop in tests 1 and 3 at +0.8%.

The maximum value of the breakdown power for the starting motor was calculated to be 12.6

MW (test 2).

The calculated values for active power are very high and show large oscillations during the

first 2 seconds of the motor start-up period (see Fig. 8). It is assumed that these results are not

physical in nature, but rather are due to one or several of the following factors:

Asymmetrical inrush current for the induction machine (DC component). Reduced accuracy of the current transformers at high currents. Non-symmetric three-phase system during the starting period. Aliasing effect (transient recorder/sampling frequency). Electromagnetic noise Non simultaneous closing of breaker poles(marginal effect) Bouncing of breaker poles (marginal effects)

Therefore, approximately the first 2 seconds of active electric power for motors and

generators during the starting period are to be neglected when assessing power variations

during motor start-up.

The deviation band, observed on the time plots for the generator active power output is also

attributed to these factors.

System modeling on computer

A system model was established on the EDSA software, a suite of programs developed by

EDSA Micro Corporation in San Diego, covering all main electrical system calculation and

simulation disciplines. The load flow and dynamical simulation modules were applied for the

case study.

The main generators were represented by a 5th order d-q axis model as shown in Figure 4. The

two main generators, although with similar rating and rotor construction, had different


9/17

Page 9 of 17

impedances and time constants. This was expected to cause power oscillations between the

generators during motor start-up.

To assess frequency variations during start-up of the new compressor motors, it was crucial to

know the gas turbine and associated control system model. This is shown in Figure 5,

covering the principal dynamics of the system. The speed control operates in isochronousmode by application of load sensor and paralleling lines. Moreover, fuel control, valve

positioner and gas turbine dynamics are represented. The frequency excursions during motor

start-up at high initial load were sensitive to the modelling of the gas turbine temperature

control system. In Figure 5 the output from the temperature control system enters the low

value select block in the speed controls governing the fuel actuator reference. If the

temperature reaches pre-set limit levels, the speed governor fuel actuator reference is

overridden by the temperature controls. As the study progressed, a number of simulations

were carried out with different settings of the temperature control loop investigating the

impact on system frequency excursions during motor start-up.

The generator excitation system is of the alternator uncontrolled rectifier type. It comprisesan S5 type programmable controller, redundant incoming feeders along with two separate

automatic control systems. (One duty and one stand-by). The S5 has a built-in rotor thermal

protection with inverse time current characteristic. If this protection is activated, it will alter

the AVR feedback signal to limit the rotor current to nominal value. The shortest protection

response time is 10 seconds at 1.4 times nominal rotor current. Motor starting simulations

determined the excitation voltage and associated average field current during the start-up time

of 14 seconds. The excitation system simulation results could thus be compared to the field

winding thermal protection characteristics. The thermal utilization by starting the new 9.0

MW motor was found to be marginally within the protection limits. This was acceptable,

considering that this protection was set conservatively and could be adjusted at site in

cooperation with the manufacturer, if required. The excitation system model is shown in

Figure 6. This model is relatively simple, as limited information was available to develop

more sophisticated representation. Still, the principal effects of AVR, feedback and saturation

are included.

Induction motors are represented as shown in Figure 7. Induction motor parameters were

estimated for the required model on the basis of speed-torque and speed-current

characteristics.


10/17

Page 10 of 17

Figure 4 - Synchronous machine model

Figure 5 - Gas Turbine Prime Mover and associatedControls


11/17

Page 11 of 17

Figure 6 - Excitation System model

Figure 7 - Induction motor model


12/17

Page 12 of 17

Comparison between simulated and measured results

Figures 8, 9 and 10 show simulated and measured 13.8 kV bus frequency, generator active

electrical power and 13.8 kV bus voltage, respectively.

Figure 8 - Generator Frequency during start-up of 6.8 MW induction motor

MeasuredMeasuredMeasuredMeasured

Calculated

60.4

[Hz]

59.8

59.6

60.8

Measured: +0.25 Hz

Simulated: +0.25 Hz

Measured: -0.8 Hz

Simulated: -0.7 Hz


Calculated

60.4

[Hz]

59.8

59.6

60.8

Measured: +0.25 Hz

Simulated: +0.25 Hz

Measured: -0.8 Hz

Simulated: -0.7 Hz


13/17

Page 13 of 17

:

Figure 9 - Generator Electrical Power during start-up of 6.8 MW induction motor

Figure 10 - Main 13.8 kV bus L-L r.m.s. voltage during start-up of 6.8 MW induction motor


Simulated

9.2 MW

10

5.0

15

MW

Measured: 15.3 MW

Simulated: 15.6 MW

11 MW


Simulated

9.2 MW

10

5.0

15

MW

Measured: 15.3 MW

Simulated: 15.6 MW

11 MW

MeasuredMeasured

CalculatedCalculated

Bus Voltage (13.8 kV)Bus Voltage (13.8 kV)

: -9.0: -9.0 %

Measured Simulated

14

13

12

kVL-L

11

0 642 Sec.

Measured: + 5.0 %Simulated: +5.4 %

Measured: -9.5 %Simulated: -9.0 %


14/17

Page 14 of 17

Looking first at the frequency envelope during start-up of the 6.8 MW induction motor in

figure 8, the following can be observed:

The shape of the measured frequency envelope is quite similar to the simulatedenvelope. The breakdown torque of the starting motor is seen to cause a relativelysharp dip in frequency 3.5 seconds after start.

The measured frequency rate of change (df/dt) is slightly higher than simulated rate ofchange, both during the initial drop and the subsequent rise after the motor exceeds

breakdown torque speed. This can be attributed to several factors, but is likely to be

partially caused by somewhat higher inertia in the GT/G train model as compared to

the actual equipment inertia. The same effect causes the simulated frequency drop to

deviate 0.1 Hz from the measured value.

Next, from the generator electrical power results, figure 9, the following is observed:

The simulation of initial and steady state power after start (although prior to fullyloading the compressor itself) are identical to the measured values

The measurements show a clear active power oscillation between the two maingenerators. Although the large active power amplitudes during the first two seconds of

the start-up period are largely influenced by factors listed under Measurements -

comments and assessments,the oscillations can in principal be attributed to the fact

that the electrical generators have different impedances. The difference is partly

related to the arrangement of the damper windings and direct axis subtransient

reactance (saturated) is 14.55 % and 10.8 % for generator A and B respectively.

Transient reactance (saturated) has a smaller difference between the generators, 20.2and 19.5 % for A and B respectively. Synchronous reactance (saturated) is 230 and

150 % for generator A and B respectively. This oscillation is also reproduced in the

simulations, but the magnitude of the simulated oscillation is much smaller. The

simulated electrical power at breakdown torque speed of the starting motor, however,

matches the measurement

Finally, from the voltage results, figure 10, the following is observed:

The simulated initial voltage dip matches the measured results indicating thatapplied motor and generator reactances in the model are close to actual values.

These values are not significantly influenced by the AVR model itself, since bothmain generator transient field time-constants are 6.0 sec. Fast excitation voltage

response will therefore only marginally compensate the initial voltage dip as the

excitation current response is largely determined by the generator design.

The following part of the voltage envelope indicates higher gain in the simulationmodel as compared to actual equipment data. The simulation gives a voltage

overshoot just after the initial dip, which is not present in the measurements.

The simulated voltage overshoot at the end of the start-up period matches themeasurements. This phenomenon is related to the induction motor breakdown torque

speed where the motor current changes from close to standstill starting level to load

current within 200 300 ms.


15/17

Page 15 of 17

Start analysis for new 9.0 MW induction motor

Starting analysis for the new 9.0 MW motor was carried out based on the developed model

for the platform electrical power system and subsequent validation by comparison between

measurements and simulations. Data from technical proposals from the pertinent compressor

motor manufacturers were used in the motor start-up simulations. Data common to all motoralternatives were:

Rated shaft power: 9.0 MW Rated voltage: 13.8 kV Rated frequency: 60 Hz Max p.u. starting current: 4.2 (including tolerances) Construction: 4 pole, (1800 rpm synchronous speed at 60 Hz) Ex classification: Eex p Temp. group: T3 Cooling method: Seawater

Results were evaluated against platform electrical system requirements as well as motor

technical constraints. Simulation results from one of the study cases are shown in figures 11

to 14. Based on the dynamical simulations carried out, it was possible to pinpoint the

bottlenecks within electrical and control systems, analyse them and finally permit go-ahead

for purchase and installation of the 9.0 MW motor.

Chart 2 - Frequency

50

52

54

56

58

61

Hertz

Time in Seconds

0 2 4 6 8 10 12 14 16 18 20

Figure 11 Simulated generator frequency during start of 9.0 MW motor

60,24 Hz

59,62 Hz59,59 Hz


16/17

Page 16 of 17

Chart 3 - Voltage

0,80

0,88

0,96

1,04

1,12

1,20

PerUn

it

Time in Seconds

0 2 4 6 8 10 12 14 16 18 20

Figure 12 - Simulated main 13.8 kV bus voltage during start of 9.0 MW motor

Chart 4 - Electric Power

0

5

10

16

21

26

MWatts

Time in Seconds

0 2 4 6 8 10 12 14 16 18 20

Figure 13 Simulated generator electrical power during start of 9.0 MW motor

Chart 6 - Excitation Voltage

-0,7

0,9

2,5

4,0

5,6

7,2

PerUnit

Time in Seconds

0 2 4 6 8 10 12 14 16 18 20

Figure 14 Simulated generator excitation voltage during start of 9.0 MW motor

1,10 pu

24,72 MW

20,61 MW

3,76 pu

0,85 pu


17/17

Page 17 of 17

Conclusion

Electrical power system dynamical behaviour can be assessed using different methods, eachrequiring different levels of input data detail. The purpose of the IPS dynamical assessment is

partly to find the correct size and parameters for the electrical equipment and partly to assist

the design engineer in selecting control systems and relay protection settings. In the design

process of an IPS it is imperative to recognise that each different project phase imposes

distinct requirements to electrical dynamics assessment. The full numerical simulation of

transient stability and dynamical behaviour with associated models of electrical power

components and their control systems represent a highly valuable design tool. Such studies

must, however, be carried out with great care as the risk of producing mistakes or useless

paper products is high. High level of academic training, high-quality simulation software,

correct assessment of operation modes, competent grasp of the interface between the power

system and the industrial process are all necessary in order to arrive at trustworthy results.The case study presented in this article, shows simulation results close enough to

measurements to have real practical application value. Although this article refers mostly to

IPS in petrochemical plants, the principles discussed are generally useful for most types of

industry.

References[1] Unitech Power Systems, Overall System Design, Industrial Power System Design

Course as if operation really mattered, December 1999.

Documents

Why When and How to Perform IPS Dynamic Studies Original Report