18/04/23

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Table of Content

To control crude oil withdrawal rates in accordance with technical and conservation considerations so as to eliminate inefficient production practices, and ensure the optimum recovery of the produceable oil and gas.

The exercise involves: Determination of Maximum Efficient Rates of

producing wells and pools Computation of Technical Allowable rates based on

MERs and other technical considerations

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The objective of Allowable Exercise

Optimum long term reservoir performance

High productivity at minimum pressure drawdown;

Uniform well inflow over the completed section;

Prevention of flow from adjacent water or gas bearing

sands; and

Prevention of excessive sand influx into the well.

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Benefits of Production Allowable

ENABLING LAW

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Section 38 and 43 of petroleum (Drilling and production) law and regulations of 1969

and its amendmentsLaw.doc

Manual of procedure guides for the petroleum inspectorate

Statutory Requirements

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The following production operations require the prior approval

of the DPR.

- Well Test including Special Well Tests and MER

- Obtaining Regular production from a well that has been

tested

- Opening up selective zone to production

- Abandoning a completed zone.

Statutory Requirements…Contd

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Reports on Production Operations:

Daily Production Summary: forwarded daily/ weekly to contain daily actual production and number of wells on test

Monthly Report of Productive Wells (MRPW): forwarded 21 days following the end of the reporting month

Maximum Efficient Rate Report: forwarded bi-annually in January and July

Well Test Result: forwarded as soon as test has been concluded

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MER Test Procedure

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Companies design and define their MER test program (in line with the procedure outlined below) and forward same to DPR , and also seek for DPR participation in the test campaign.

Procedure to be adopted depends on the type of well 2 categories are defined as follows:

→New Well Procedure: applied to well that have never been MER Tested. Same procedure applies to worked-over wells →Routine MER Procedure: applied to wells on regular production

Newly completed/worked-over wells: Production test period of six weeks on at least 5 incremental steps of choke opening

For wells already on regular production: test on at least 3 incremental steps of choke opening

MER Test Procedure….Contd

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MER Test Sequence:1st Step: 3 hours Stabilization for each choke size provided stabilization criteria are met2nd Step: 6 hours Flow measurement

End of MER test

Cho

ke o

peni

ng

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3

Flow Rate

1st Step

2nd Step

WELL 1

time

MER Test Procedure….Contd

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Stabilization Criteria:Based on Flowing Tubing Head Pressure (FTHP) and test separator flow measurements stability over the stabilization period

→Flowing Tubing Head Pressure:(FTHPmax - FTHPaverage) / FTHPaverage ≤ 0.5%(FTHPmin - FTHPaverage) / FTHPaverage ≤ -0.5%

Or, FTHPmax - FTHPmin ≤ 1%

FTHPaverage

→Test Separator Flow Rates, Q

(Qmax - Qaverage) / Qaverage ≤ 5% (Qmin - Qaverage) / Qaverage ≤ -5%

Or,

Qmax - Qmin ≤ 10% Qaverage

MER Test Procedure…..Contd

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Carrier Wells:Although test by difference could be allowed for wells with potential too low to be produced individually, individual well test is the recommended practice

SAMPLING:Usually 3 Flowline samples are collected (at strategic periods during the 6 hours Flow Measurement) for BSW & API analysis. Sand detection and measurement is also done

For Accurate Flow Data:Test separator should be at the right static pressure No leakage at the header valvesProper measurement of gas lift volumeTake measurements at sufficiently stable flow

Intelligent Wells

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Yes

Start

No

Allocation By Zonal Production Testing

Model Calibration by zonal production testing

Daily Allocation

Monthly/ Quarterly production testing

No

Yes

Determine Error Between Model and Measurements

Is the Error Within Desired Allocation Accuracy?

Perform Commingled Production Test (Qtot, FBHPs)

Use Model and Measured FBHPs to estimate Qtot

Measure Build-Up Pressures on Other Zones (SBHP)

All Zones Tested?

Close All Zones

Open one zone

Reconcile Model to Honour Production Test

Yes

Is an Obligatory Production Test Sheduled?

Use Reconciled Model, FBHPs to allocate Production to the Individual Zones (Qtot, Q1, Q2)

Are the Results as Expected or has no Significant Change in

the Well Pressures been

Set up Inflow Model (Pipesim, Prosper)

Perform MER Test (FBHP, Q) on The Open Zone

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Submission

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All MER Test Results must be endorsed by DPR rep(s)

Results of MER Test and request to obtain regular production from a well should be forwarded to DPR in the prescribed form and format, and should reflect the following:-Date of Test-Duration of Test-Reservoir Name-Choke size-Static & Flowing Bottom Hole Pressure (SBHP/FBHP)-Flowing Tubing Head Pressure (FTHP)-Downhole Temperature & Tubing Head Temperature-Fluid Rates(Gross Liquid Rate, Net Oil, Gas Rate, Water)-BS&W-RSI & GOR-Sand Cut-SG or API

MER DETERMINATION

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Plots of FTHP vs Rates and chokes vs Rates are made on the same graph paper

The point of intersection of the 2 plots indicates the point of stable equilibrium and the corresponding rate gives the maximum efficient rate

Generally the maximum efficient rate ≥ allowable rateAllowable rate is defined by scaling down the MER considering factors such

as: Wells Producing History The reserves carried by the pools from which the wells are producing The well’s productivity index (PI) Draw-downs Producing GORs RSI Water cut Sand Production Flowing Tubing Head Pressure The general performance of the individual reservoirs Pressure Decline of the pool of interest Injection volumes into project pools

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Allowable Computation

Water cut Water production is limited to 10% in a water drive reservoir depending

on the viscosity of the crude. BS&W is expected to be zero in a non-water drive pool otherwise the

problem of water channelling or communication would be suspected.

Sand Cut Detrimental to the reservoir, surface and sub-surface equipments Sand production is limited to 5 lb/1000bbl. For reservoirs deeper than

8000ft, any sand production is viewed seriously because below this level, the formation should be more consolidated.

Productivity Index A Productivity Index below 5 b/d/Psi indicates that an acidization job

may be necessary.

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Allowable Computation….Contd

GOR In a water drive or pressure maintained reservoirs, GOR is limited to

125% of the initial solution GOR (Rsi). Producing GOR is limited to maximum of 4,000 scf/bbl unless the

produced gas is to be used on an approved project.

Draw-Down A draw down of between 50 and 100 psi is considered optimum. An

upper ceiling of 150 is permissible in exceptional cases.

Flowing Tubing Head Pressure (FTHP)

This is used to indicate well’s condition. Drastic Fall in THP could be as a result of mechanical obstruction,

sand bridging/ impairment of sand face or water loading. High THP could indicate high GOR.

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Allowable Computation…Contd

Beyond The Tolerance Limits

PENALTY FACTORS FOR PROBLEM WELLS.doc

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Problem Wells

Reservoirs where oil production is maintained with the aid of a Pressure Maintenance (PM) Scheme such as water injection, gas injection, water alternate gas injection (WAG), gas recycling, steam projects.

10 E & P Companies are operating various Pressure Maintenance Projects in the country. The Companies are Chevron, Star Deep, Esso, Mobil, Total Upstream, Total E & P, SNEPCo, Oriental, NAE and NAOC.

There are currently 120 active project reservoirs in the country operating acreages.

PROJECT POOLS

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i.Oil rates based on Zero-Net Voidage computed at prevailing injection volumes

ii.Instantaneous and Cumulative Injection-Withdrawal Ratios (IWR)

iii.Pressure Decline Analysis

iv.GOR, water cut trends

v.Recovery Fractions and Remaining Reserves

vi.Sum of MER test rates for each pool

vii.Current production rates for each of the pools

Key Performance Indicators (KPI) for Pressure Maintenance (PM) Projects

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•Daily, Monthly and cumulative oil, gas and water production data

•Daily, Monthly and cumulative gas and water injection data

•Reservoirs Pressures and PVT properties

•Remaining Reserves as of 01/01/2015

•1st Half 2015 MER tests results for active producing wells.

INPUT DATA FOR 2H 2014 ALLOWABLE COMPUTATION

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Sample Allowable WorksheetSPDC 2H 2014 ALLOWABLE.xls

Project Pools2H 2014 PROJECT POOLS.xls

Allowable Distribution/

Crude Stream/ CRUDE STREAM 2ND HALF OF 2014.xls

Summary Table

SAMPLE RESULTS

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Flowing Not FlowingADDAX 83 72 59 15AENR 12 9 8 1ALLIED ENERGY 2 0 2 1AMNI 20 6 14 2ATLAS 3 0 2 1BRITTANIA-U 1 0 1 1CHEVRON 306 234 302 33CONSOLIDATED 9 2 5 2CONTINENTAL 18 28 11 3DUBRI 2 2 4 1ENERGIA 8 0 4 1ESSO 29 2 3EXPRESS 1 4 2 1MIDWESTERN 11 8 10 1MOBIL 125 205 147 25MONIPULO 12 0 2NAE 5 4 1NAOC 205 145 105 35NDPR 4 2 4 1NPDC 86 19ORIENTAL 20 1 4 1PAN OCEAN 33 18 40 8PILLAR 2 0 2 1PLATFORM 8 2 4 1SEEPCo 14 1 2 1SEPLAT 66 2 34 5SNEPCO 13 5 1SPDC 452 224 298 53STARDEEP(Agbami) 16 2 1TOTAL E & P 93 38 64 11TOTAL UPSTREAM 20 9 1WALTERSMITH 6 2 5 1

GRAND TOTAL 1685 1005 1155 234

COMPANYNo of Producers

Reservoirs Fields

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NO OF ACTIVE PRODUC ERS

MER (bopd)1H2014

AVERAGE PROD RATE

(bopd)

1H14 2H14 % Difference

1CHEVRON 50 153 110,640 99,251 93,340 95,930 3%

2 MOBIL 17 105 255,331 171,961 235,950 181,000 -23%

3 TOTAL E & P 14 70 96,690 85,585 76,750 60,280 -21%

4 NAOC 9 31 9,167 3,764 7,975 3,155 -60%

6 SNEPCo 5 13 259,918 150,516 171,000 183,500 7%

7 ESSO 10 29 276,247 192,317 220,000 189,500 -14%

5 NAE 4 5 27,100 23,732 31,300 22,000 -30%

8 STARDEEP 2 16 244,030 241,555 260,000 235,000 -10%

9 TUPNI 6 20 179,500 179,500 0%

117 442 1,279,124 968,682 1,275,815 1,149,865 -10%SUM

TABLE 1 - SECOND HALF 2014 ALLOWABLE FOR PROJECT POOLS

S/No COMPANYNo of

Project Pools

PRODUCTION INDICES ALLOWABLE (BOPD)

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1 ALLIED ENERGY SR 3,364 2,300 2,625 2,356 2

2 AMNI SR 26,255 22,115 24,777 21,032 -5

3 ATLAS SR 1,704 1,300 1,476 1,350 4

4 CONSOLIDATED SR 1,829 1,643 1,878 1,340 -18

5 CONTINENTAL SR 18,328 16,706 18,328 15,676 -6

6 DUBRI SR 390 270 329 329 22

7 EXPRESS SR 1,985 1,500 1,137 1,130 -25

8 NPDC SR 92,866 83,951 136,960 127,935 52

9 MONIPULO SR 4,200 4,200 4,282 4,200 0

10 SEPLAT JV- INDIGENOUS 74,898 74,662 83,252 77,186 3

SOLE RISK TOTAL 225,819 208,647 275,044 252,534 21

11 STARDEEP(Agbami) PSC 265,130 260,000 244,030 235,000 -10

12 TOTAL UPSTREAM PSC 196,842 179,500 196,842 179,500 0

13 ADDAX PSC 93,231 82,549 94,921 86,892 5

14 AENR PSC 10,340 9,065 10,719 8,990 -1

15 ESSO PSC 124,423 103,000 276,247 189,500 84

16 NAE PSC 36,200 31,300 27,100 22,000 -30

17 SNEPCO PSC 215,000 171,000 259,918 183,500 7

18 SEEPCo PSC 16,901 16,041 17,731 16,190 1

19 TOTAL (USAN) PSC 175,925 95,700 0 0 -100

PSC TOTAL 1,133,992 948,155 1,127,508 921,572 -3

20 BRITTANIA-U MARGINAL 2,850 2,500 2,850 2,800 12

21 ENERGIA MARGINAL 6,019 5,850 10,391 8,050 38

22 ORIENTAL MARGINAL 57,196 40,650 52,677 41,040 1

23 PLATFORM MARGINAL 2,220 2,660 3,394 2,862 8

24 MIDWESTERN MARGINAL 16,625 23,940 25,995 21,590 -10

25 NDPR MARGINAL 1,400 3,270 4,804 4,160 27

26 PILLAR MARGINAL 3,307 3,100 4,764 3,980 28

27 WALTERSMITH MARGINAL 6,756 6,057 6,363 5,675 -6

MARGINAL TOTAL 96,373 88,027 111,238 90,157 2

28 CHEVRON JV 271,142 249,572 294,020 264,211 6

29 TOTAL E & P JV 157,925 126,983 121,908 84,501 -33

30 MOBIL JV 715,390 607,525 717,583 550,424 -9

31 NAOC JV 174,958 163,565 197,436 82,137 -50

32 PAN OCEAN JV 8,864 7,831 8,473 8,078 3

33 SPDC JV 656,931 357,151 607,299 440,491 23

JV TOTAL 1,985,210 1,512,627 1,946,719 1,429,842 -5

3,441,394 2,757,456 3,460,509 2,694,105 -2

2014 TECHNICAL ALLOWABLE

S/N COMPANY1H 2014

ALLOWABLE (BOPD)

2H 2014 ALLOWABLE

(BOPD)

2H 2014 MER (BOPD)

TOTAL

% DIFFERENCE

(1H14 vs 2H14)

CONTRACT TYPE

1H2014 MER (BOPD)

2% decrease as against

the 1H 2014 TA

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944,874 620,917 863,884 269,964 252,534 921,572 90,157 1,429,842

2011/224331

SECOND HALF 2014 TECHNICAL ALLOWABLE DISTRIBUTION BY ASSET

AREA

SECOND HALF 2014 TECHNICAL ALLOWABLE DISTRIBUTION BY CONTACT

TYPEPSC MARGINAL JVMFIO SREAST AREA WEST AREA

DEEP OFFSHORE

35%

23%

32%

10%

TECHNICAL ALLOWABLE DISTRIBUTION BY ASSET AREA

EAST AREA WEST AREA DEEP OFFSHORE MFIO

10%

34%

3%

53%

Technical Allowable Distribution According to Contract Type

SR PSC MARGINAL JV

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1H2011 2H2011 1H2012 2H2012 1H2013 2H2013 1H2014 2H2014 1H2015

Tech Allow. 2.8779612.7346662.759676 2.59444 2.7752232.7246442.7574562.6941022.958145

2.5

2.6

2.7

2.8

2.9

Te

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wab

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BO

PD

)Technical Allowable Trend In The Past Four Years

:Technical Allowables are granted on well basis They are not transferable An allowable rate represents the ceiling of production

permitted from a well Under-production from well cannot be made up from a

more prolific well in the pool, nor shall it be allowed to grossly overproduce a well to compensate a lost production in a previous period or anticipate loss in future production

At any time, the permissible production shall consists only of allowables of producing wells and production from test wells yet to be granted allowables

Production in excess of allowable from wells shall constitute an infringement and attracts sanction

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Operating Guidelines For Allowables

Infringement of Rules On MER and/or Allowable - The Penalties

Scenario Action / Penalty 1. *No MER Submission  

…..Deliberate ( Example: Companies failing to conduct MER because of the perceived loss of production associated with MER test and the consequences in meeting set business targets)

(i) Assign Zero Allowable Rate to Well(s). (ii) Advice Company to shut-in the wells

….Technical ( Examples: due to problem wells, ageing facility etc.)

(i) Engage companies to evaluate proposals, review well performances and make recommendations. (ii) Engage companies to ascertain its production optimization techniques.

….Logitics/ accessibility of well test locations

(i) Engage companies to ascertain its production optimization techniques. (ii) May consider MER test conducted on annual basis instead of bi-annual as required

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Infringement of Rules On MER

Allowable review and Supplementary Allowable Surveillance

– Q vs Allow., Rsi vs GOR, Sand, BSW, production profile, etc

Production Audit Engagement/ Meetings

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Post Allowable Engagements

Infringement of Rules On MER and/or Allowable - The Penalties

Scenario Action / Penalty

2. Production above the authorised Technical Allowable

(i) Over-produced wells are flagged down and recommended for beaning down (ii) Restitution of the over-produced crude depending on the magnitude of the over-production. Penalty of money equivalent may be considered

3. *Wells not on approved production/ No Technical Allowable

Proposal: Assign penalty of monetary equivalent of the 20% of produced crude

*DPR communicates approved allowable rates to Crude Oil Marketing Division (COMD). *Crude Lifting from Fields on no approved Production is not allowed by COMD(i.e fields for which no MER was conducted and no allowable rates granted)

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Infringement of Rules On MER ….Contd

Intermittent Producers Old Wells Test Vs Choke Sensitivity and BS & W Reliability of Well Performance Simulation Model Gas-Lifted Wells (optimization of lift gas) ESP-Assisted Wells Flow Assurance

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Special Cases

THANK YOU

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