Production Efficiency
Guidance notes
January 2010
Contents
• Metric Principles
• Definitions
– Production efficiency components
– Total Annual throughput
– Well potential
– Plant potential
– Export potential
– Market potential
– Structural Maximum Production Potential (SMPP)
– Summary of Field Production measures
• Gas Balance
• Production Constraints
– Oil & Gas field
– Gas field producing under contract
PE Guideline - Metric Principles
– The intention of the Production Efficiency (PE) metric is to provide a tool to help
make improvements to production performance, by creating a standard to:
• Benchmark operations against
• Quantify the size and value of operational excellence opportunities
• Show the primary areas to improve performance on each metric
– PE is an objective metric, not a subjective one, so 100% PE would imply “perfect”
operations, such that additional production could only be achieved through structural
changes. Structural changes require either further investment to increase the
Structural Maximum Production Potential (SMPP) or negotiating additional Market
Maximum Production Potential (MMPP)
Definitions: PE Components
Structural Maximum Production Potential
Structural Maximum Production Potential (SMPP) is the lowest structural production
potential of the well, plant and export systems including third party processed volumes*.
Structural MPP is the sum over the year of the monthly MPP figures evaluated at the
beginning of each month.
•
•
•
•
*
Well production potential is the sum of the individual operating well flow rates
tested at the optimum operating conditions plus the sum of the third party forecast
well potential.
Plant production potential is the maximum monthly throughput potential
measured daily, including third party forecast throughput.
Export potential is the maximum monthly physical potential available through
ships and/or pipeline measured daily, including third party forecast throughput.
Market Potential (applicable only to gas fields producing under contract) is the
sum of the daily contract nominations for the month.
Third party processed volumes include only processed flows and not ‘up and over’ flows
Definitions: Annual throughput definition
Total annual throughput
This is the total processed throughput which is delivered to the export* system. It
includes third party volumes which undergo processing at the production facility,
but not "up and over" volumes which pass through without being processed.
Total annual throughput
=
annual oil production (including
condensate and NGL if not included in gas)
+ oil processed for third parties
+ wet gas exported* (exported gas including NGL if not
included in oil, but excluding flare). This will also include
any third party gas.
* For gas production, export system means all gas that is delivered off the production facilities
i.e. the sum of gas exported to pipeline and re-injection. This should not include gas lift.
Definitions: Well potential
Well Potential = The sum of the individual operating well flow rates tested at
optimum operating conditions plus the sum of the third party
forecast well potential including gas for fuel, flare and re-injection
• The optimum operating conditions being the flow potential for a well at the minimum 1st stage
separator pressure or the optimum drawdown for good reservoir management (e.g. to prevent
water or gas coning and sand free flow).
• The 1st stage separator pressure being the pressure in the first separator downstream of the well
in question.
• Losses due to mechanical well impairment, localised reservoir restrictions or voidage
replacement at the time of the well test will not be captured by the production potential.
• An “operating well” is defined as a well that is economically viable to operate under the operating
conditions of the field. This includes the potential of an operating well that is shut-in for any
reason (e.g. workover, annual valve maintenance, reservoir monitoring, etc)
• If a “non-operating well” is not economic to be brought back onstream and is to be permanently
shut-in or abandoned then the well flow potential should be removed from the overall well
potential.
• New well potential should only be included when it is brought onstream.
Definitions: Plant potential
Plant potential = Sum of the daily throughput potential of the plant
 The throughput potential is measured as the quantity of oil, gas, condensate and
NGLs that could be processed over a set period of time when no interruptions
occur.
 Throughput potential should include gas for re-injection, fuel or flare.
 The constraint on the throughput can be from any of the following; water, gas, oil
processing, flare limits or water disposal limits
 Plant potential should not be reduced for planned or unplanned shut-downs
 New or modified plant giving additional potential for processing should only be
added to the plant potential when brought onstream
 The boundary between i. well and ii. plant is at the flange of the wing valve
downstream of the christmas tree, so underwater equipment may be part of the
plant / host facility rather than the well.
Definitions: Export potential
Export potential = Maximum volume that can be exported through the pipeline or
shuttle tankers (including third party volumes if processed) and
re-injection.
 Daily sum of the potential export volumes through the export system without any
interruptions, planned or unplanned
 Re-injection potential (this should not include gas lift)
 Includes oil, gas, condensate and NGL potential
 Includes any pipeline specification which may limit the export volumes (e.g.
maximum % water, H2S PPM, wax content)
 Market constraints should not reduce the Export potential.
Definitions: Market Potential (gas fields)
Market Potential = for some gas fields production is constrained by the type of gas
contract that is
in place, and this can be the overriding
consideration when
calculating the SMPP. The monthly volume
should be the sum of the daily gas
nominations for that month. For
the annual shut down when fields are not nominated the number
should be zero.
 Daily sum of the gas nominations
 When reporting an individual field the total annual production should be the production from that field’s reservoir and
should not include any substitution or attribution volumes.
SMPP is the lowest constraint on
production
Production
SMPP
Losses recorded against
SMPP *
Oil
Well
availability
or reservoir
availability
Gas
Water
Plant potential
Export
Market
Total
Annual
Throughput
* Losses include an “unallocated” category where the reasons for the difference between SMPP and Actual
Production have not been determined
Summary of Field Production Measures
Total Annual Throughput is the total processed throughput which is delivered to the
export system. It includes third party processing volumes, but excludes “up and over”
volumes.
Total Annual Production is the total produced and processed volume
Gas
Oil
Total Annual
Throughput
3rd Party Gas
3rd Party Oil
Total Annual
Production
Wet Gas
Evacuated
Oil Production
Gas Balance
FUEL GAS
FLARE GAS
GAS EXPORT
GAS PRODUCTION
GAS THROUGHPUT
3RD PARTY
GAS PRODUCTION
PRODUCTION FACILITIES
GAS RE-INJECTION
(not gas lift)
Production Constraints – Oil & Gas Fields
Constraint on Production for fields porducing under Contract
MONTH
Structural maximum potential for each area by month MMboe
1
2
3
4
5
6
7
8
9
10
11
12
No. of % by area
months*
**
7
58%
Well and reservoir potential
1.3
1.3
1.2
1.4
1.4
1.4
1.6
1.6
1.6
1.5
1.5
1.4
Plant potential
1.5
1.6
1.6
1.6
1.6
1.5
1.5
1.5
1.5
1.6
1.6
1.5
0
0%
Export potential
2.0
2.0
2.0
2.0
2.0
2.0
2.0
2.0
2.0
2.0
2.0
2.0
0
0%
Market potential
1.6
1.6
1.6
1.5
0.2
0.0
0.0
0.0
1.0
1.7
1.8
1.5
5
42%
SMPP = minimum
1.3
1.3
1.2
1.4
0.2
0.0
0.0
0.0
1.0
1.5
1.5
1.4
10.8
=Annual
SMPP
Actual Production MMboe
1.2
1.3
1.1
1.2
0.2
0.0
0.0
0.0
1.0
1.3
1.5
1.4
10.2
Production Efficiency %
Lost Production MMboe
94%
0.1
0
0.1
0.2
0
0
0
0
* - Number of months constraining production. ** - Percentage of the year when production was constrained by the category
For assistance, the above constraints spreadsheet can be downloaded from the DECC website.
All gas fields which producing under contract, Operator must also complete supporting spreadsheet and send it with PE return
0
0.2
0
0
0.6
Production Constraints – Gas fields
Constraint on Production for fields porducing under Contract
MONTH
Structural maximum potential for each area by month MMboe
1
2
3
4
5
6
7
8
9
10
11
12
No. of % by area
months*
**
7
58%
Well and reservoir potential
1.3
1.3
1.2
1.4
1.4
1.4
1.6
1.6
1.6
1.5
1.5
1.4
Plant potential
1.5
1.6
1.6
1.6
1.6
1.5
1.5
1.5
1.5
1.6
1.6
1.5
0
0%
Export potential
2.0
2.0
2.0
2.0
2.0
2.0
2.0
2.0
2.0
2.0
2.0
2.0
0
0%
Market potential
1.6
1.6
1.6
1.5
0.2
0.0
0.0
0.0
1.0
1.7
1.8
1.5
5
42%
SMPP = minimum
1.3
1.3
1.2
1.4
0.2
0.0
0.0
0.0
1.0
1.5
1.5
1.4
10.8
=Annual
SMPP
Actual Production MMboe
1.2
1.3
1.1
1.2
0.2
0.0
0.0
0.0
1.0
1.3
1.5
1.4
10.2
Production Efficiency %
Lost Production MMboe
94%
0.1
0
0.1
0.2
0
0
0
0
* - Number of months constraining production. ** - Percentage of the year when production was constrained by the category
For assistance, the above constraints spreadsheet can be downloaded from the DECC website.
All gas fields which producing under contract, Operator must also complete supporting spreadsheet and send it with PE return
0
0.2
0
0
0.6