Topaze Guided Session #4 - KAPPA Eng

Ecrin v4.20 - Doc v4.20.01 - © KAPPA 1988-2011 Topaze Guided Session #4 • TopGS04 - 1/16

Topaze Guided Session #4

A01 • Introduction

This guided session is an introduction to the basic facilities of the reservoir production profile

option in Topaze. Topaze can be used in two distinct manners:

- Match field profile: A target field profile is defined and the program automatically

determines the necessary drilling schedule, on a monthly basis, to meet the target.

- Build field profile: The user defines the drilling schedule, and the field production is built

accordingly.

This session will illustrate both approaches.

B01 • Oil – Water Drive Case: Build Field Profile

B01.1 • Starting a new Topaze Project

Click on New Document, set the document structure to multi-well and check the option

‘Generate the production profile’, as shown below:

Fig. B01 • Multi-well new document


Click on Next to confirm the document creation. The Multiwell tab is now active, and the

control panel is positioned to the Multiwell page. Click on the Profile Pane to initialize the

profile session:

Fig. B02 • New Profile Session

Select the ‘Build field profile’ option, and change the first production year to January 2012.

B01.2 • General Data Input: Gas and Water Usage

Click on ‘Next’ to enter the ‘Gas / Water Usage’ dialog:

Fig. B03 • Gas and Water Usage Input Dialog


We will accept all default values in this dialog, knowing that the various options are:

Gas lift Default values ensure that gas lift will start when a well cuts 15 %

water and the required gas volume per well is 2 MMSCFD.

Gas usage

The necessary field fuel gas is defined together with the volume of

allowed flare gas. If the box ‘Export Gas’ is ticked no gas will be

injected. By default the date of exported gas coincides with

production start-up.

Water usage mode

The default case specifies that 80 % of voidage (qoBo +qwBw) will

be replaced by the aquifer influx, requiring 20 % of voidage volume

to be replaced by injected water. Total Reservoir Voidage times

(Replacement_Ratio-Voidage_Replaced_By_Aquifier). Replacement

ratio: percentage of total withdrawal to be replaced by water

Water injector

The default value of 20,000 stb/d specifies the injection capacity of

each injection well and is used to determine the number of required

water injection wells.

B01.3 • General Data Input: Drilling and Workovers

Click on the Tab ‘Drilling/Workovers’. Apart from the rig constraints box that you need to

uncheck, you can keep all default values in this dialog:

Fig. B04 • Drilling and Workovers Input Dialog


A few words can again be said on the options detailed in this dialog:

Rig constraints

The constraints box having been unticked, means that the forecast

can be put in directly, without any constraints on well availability.

Weather window: If all Months are ticked, there will be no rig

constraint. Workover can be added if it is expected that all wells need

a regular workover such as stimulation or pump replacements. The

well improvement option can be used if a workover increases

production from the well.

Drilling ability

Here the drilling performance is entered. Main parameter is the ‘Days

to Drill a Producer’, as the well comes on stream the applicable

number of days after drilling start-up. A drilling learning curve (Rig

Crew Learning Speed) with a value according to the acquired

experience can also be applied. In this case the maximum and

minimum durations must be entered and the learning speed can be

adjusted to: Very poor, Poor, Average, Good, Very good or Excellent

in order to take into account the drilling team ability (time to go from

maximum to minimum drilling duration). The plot illustrates the

applicable learning curve or the constant days to drill a well. Any

changes should be followed by a click on . Note that the

calculation internal time step is months and drill time will be taken as

the nearest integer of months.

B01.4 • General Data Input: Field Water Cut (Fw)

Click on the Tab ‘Field Water Cut (Fw)’:

Fig. B05 • Field Water Cut Input Dialog


The total field water cut (Fw) development is defined as a function of total net production

(Np/N). These values are only valid for the total field and cannot be used to forecast gross

production rates for individual wells. For all models, except the ‘No Water’ option, one has to

enter the abandonment recovery factor and water cut. The various models are:

Stiles Layered reservoirs with different kh values. If chosen the user is

automatically reminded to fill in the layer data.

Buckley-Leverett Flooding of a homogenous sand package.

Empirical

The shape can be manipulated to fit observed data. If chosen, the

user has to define the water cut development using three additional

parameters. See the on-line help for a further definition of the

available methods. This model is required if the user wants to match

historical field data that can be loaded (entered) using the

button and matched with the

button.

In this session we will use the Buckley-

Leverett option with the following

parameters:

Hit ‘Apply’ to validate the changes.

It is necessary to enter the relative permeability relationship for Oil-Water. Click on to

enter the relative permeability dialog, and enter the following data under the ‘Kr Data’ tab:

Press the ‘Kr Two-Phase’ tab to visualize the corresponding relative permeability curves:


Fig. B06 • Relative Permeability Input

B01.5 • General Data Input: GOR

Press the tab ‘GOR’: There are five types of GOR developments, four of them being based on

the methods as described by Neal Teague (Oil & Gas Journal, Feb 1994), and a constant GOR

value. Here we will use ‘Constant’ at default value. An oil reservoir under active water drive

has a constant GOR, assuming the reservoir pressure stays above bubble point.

B01.6 • General Data Input: Constraints

Press the tab ‘Constraints’:

Fig. B07 • Constraints Input


The constraints entered here can correspond to the operational field production limitations due

to logistics and storage, for instance. The following can be specified and modified at any point

in time: oil rate, gas rate, water production, water injection, total liquid rate.

In any Topaze forecast, the governing phase production, Oil or Gas, is driving all the other

phase productions or injections. For this reason, any of the above constraint can be translated

into a constraint on the main phase. This is called the minimum constraint and it is the value

used internally to check the main phase production. Note that at a given time step, this

minimum constraint is a function of Np/N. The minimum constraint can be plotted on the Field

production plot (Well schedule tab). With time, varying colors indicate what constraint is

causing the bottleneck.

Constraints can be handled in 3 ways:

Undefined: When a constraint value is zero, Topaze will ignore it. This constraint will have no

effect on the calculations or the results.

Flag only: In this case the constraints have no impact on the production. In the Tables and

Results sections, those values that violate a constraint are highlighted in red. Note for instance

that in an oil case, if the gas production exceeds the gas constraint, then necessarily the oil

production exceeds the ‘minimum constraint’. So violating a constraint other than the one on

the main phase entails the violation of that main phase ‘minimum constraint’ too. Note that

violated means bigger or equal.

Active: At each time step Topaze calculates the minimum constraint and defers any excess

production to future time steps. In the results/tables Topaze will still highlight what constraints

have been violated or reached, to indicate the bottlenecks. Also, in the Results dialog, Topaze-

Profile will report any deferred production that could not be re-allocated.

We will not impose any constraint here; click on ‘Next’ to move to the next stage of the project

definition – the well profiles.

B01.7 • Well Profiles

The Well Profile facility allows the user to enter new Well Production Profiles or to modify

existing ones. Some defaults profiles (named Producer#1, Gas Injector, Water Injector) are

pre-defined. New well profiles can be defined to be used either for prospective wells (manually

added by the user) or for automatic wells (added by the simulation). Their characteristics -

initial rate, number of declines, decline coefficient - can be modified in this dialog by the user.

In this session we will define two well profiles, with a unique decline in each case. Let us start

with the modification of the default profile ‘Producer 1’, by entering an initial rate equal to

5000 STB/D, a final rate of 250 STB/D, a delay of 0.5 year (this is the time before the decline

steps in), and set the decline to be harmonic with a factor of 0.5. Press ‘Apply’ to visualize the

following curve:


Fig. B08 • Defining a harmonic decline on Producer 1

Press now the button ‘New’ to create a new well type, and rename this new type to ‘Producer

2’. Enter an initial rate of 3000 STB/D, a final rate of 150 STB/D, no delay (0 year) and a

harmonic decline with a factor equal to 0.5:

Fig. B09 • Defining a new decline type on Producer 2


Click ‘Next’ to validate the user input, and validate with OK:

Fig. B10 • Topaze main screen after inputting the general data and the well profiles

B01.8 • Adding Prospective Wells

As can be seen in Figure B10, the production profile remains empty: no well has been

scheduled and the next step consists in adding wells and production starting points.

Double click in the Well Schedules table to create a new well; the following dialog will show up:

Fig. B11 • Creating a Prospective Wells


Accept the default to create a well of type Producer 1 starting in January 2012. Similarly,

create two new wells of the same type (Producer 1) starting respectively in February and

March 2012. Add now 3 producers of type Producer 2, starting respectively in January,

February and March 2015. The Topaze main screen will then be showing a non-zero field

production:

Fig. B12 • Topaze main screen after the creation of the 6 producers

The program has added the six wells plus a water injector. The number of injectors is

determined automatically, following the parameters in the tab for Gas/Water Usage under

General Input. In case a mistake was made while entering the well schedules, this can be

corrected by clicking on the button in the appropriate well line in the spreadsheet.

The total field forecast, including the water and the gas production, is recomputed as soon as a

new well is added or modified and can be visualized in tabular or graphical formats, as can be

seen below:


Field production forecast, tabular view:

Viewing the total liquid rate graph:

Viewing the total gas rate graph:


B02 • Oil – Water Drive Case: Match Field Profile

B02.1 • Switching to the Match Field Profile Method

In the previous session we have created a field production in a forward manner, from the

direct input of the drilling schedule. We will now perform the inverse, and use the Topaze

‘Match Field Profile’ option to infer automatically the necessary drilling schedule required to

meet a field production target.

Click on the Main Infos button ( ), and check the ‘Match field profile’ check-box. Do not

keep the prospective wells previously defined. The Topaze main screen will look as follows:

Fig. B13 • Topaze main screen after switching the document to ‘Match Field Profile’


Click on the Field Profile button

( ) to visualize the

parameters controlling what is now

the input field profile:

Exit with OK to accept all default

values.

Click on the Well Profiles button ( ) to edit the ‘Producer 1’ default well profile; in the

Well Profile dialog use the ‘From field’ option to adjust the decline factor from the global field

profile. Hit ‘Apply’ to validate the changes.

Fig. B14 • Producer 1 default field profile

Edit the Producer 2 profile and delete it.


Click now on the Run Simulation ( ) button, and change the final initial rate to 4100

STB/D before to proceed with the Topaze field simulation:

Fig. B15 • Topaze main screen after field simulation

A total of 116 producers and 12 injectors were scheduled by the simulation.

B02.2 • Adding Constraints

Let us now assume that for logistic reasons the total oil rate cannot exceed 350,000 STB/D. To

enter this constraint, click on the General Input button in the Constraints tab, and enter

350,000 STB/D in the Oil rate column for a constraint starting in January 2012:

Keep this constraint as ‘Flag only’ for the time being, and click on OK to visualize it in the field

production graph (click on the option):


Fig. B16 • Field production with inactive total oil production constraint

It can be graphically seen that the total field production goes beyond the oil production

constraint for a few years after 2017. Visiting the ‘Tables’ tab of Topaze helps checking that

the production excess lasts for 6 years, between 2017 and 2022:

Let us now modify the field profile to make sure that the constraint will not be violated. Go

back to the constraint edition dialog (General Input option), and check the constraint status

from ‘Flag’ to ‘Active’. Click on OK to see the resulting modified profile in the Well Schedules

tab:


Fig. B17 • Field production with an active total oil production constraint of 350,000 STB/D

Click on Results ( ) to see that the number of producers has been changed to 113

(116 before), and that 10 injectors are now planned, instead of 12:

Fig. B18 • Fields Results

Topaze Guided Session #4 - KAPPA Eng

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Transcript of Topaze Guided Session #4 - KAPPA Eng