Reservoir Engineering

BC Oil and Gas Commission

March 2013

BC Well Testing & Reporting

Requirements

1) Drilling & Production Regulations

• Pressure Testing Requirements

• Gas Well Flow Testing Requirements

2) Well Testing & Reporting

• Pressure Tests • Test Types

• PST Survey Report Form

• Common Questions

• Wellbore & Formation Gradients

• Data Quality

• Flow Tests • Test Types

• Deliverability Test Report

• Common Questions

• Clean Up Flows & Underbalanced

Drilling

Presentation Outline

3) Annual Pressure Surveys

• Minimum Test Requirements

• Annual Pressure Survey ‘Tips’

• Application for Modification

• What Pools Require Testing This

Year?

4) Website Orientation

• On-line Forms & Tables

Drilling and Production Regulations

Section 73 – Reservoir Pressure Measurements:

73 (1) Subject to subsection (5), a well permit holder must ensure that the static bottom hole pressure of

each completed zone of each of the permit holder's oil or gas wells is measured before initial oil or gas

production.

(2) Subject to subsection (6), a well permit holder must ensure that the static bottom hole pressure of

each of the permit holder's producing pools and observation wells is measured once every calendar year.

(3) A well permit holder must report all static bottom hole pressures and the duration of the resulting shut-

in period to the commission within 60 days after the date on which the pressures were measured.

(4) A well permit holder must ensure that, when static bottom hole pressures are measured, the surveyed

wells remain shut-in until the reservoir pressure has been attained in the well bore or until sufficient data

are available to permit the calculation of the reservoir pressure and, in the latter case, details of the

reservoir pressure calculations are included in the report required under subsection (3).

(5) Subsection (1) does not apply with respect to a well completed in an unconventional zone listed in

Schedule 2 if the commission has released, under section 17 of the Oil and Gas Activities Act General

Regulation, well reports and well data that include a static bottom hole pressure measurement from the

same unconventional zone within a 4 km radius measured from the wellhead of the well.

(6) Subsection (2) does not apply with respect to a well completed in an unconventional zone listed in

Schedule 2.

4 Pressure Test Regulations

5 Pressure Test Regulations Continued

Schedule 2 – Unconventional Zones:

Field Zone Name Distance (m)

Horn River Muskwa-Otter Park 100

Horn River Evie 100

Helmet Muskwa-Otter Park 100

Helmet Evie 100

Liard Basin Besa River 100

Northern Montney Montney 150

Northern Montney Doig Phosphate-Montney 150

Heritage Montney 150

Altares Doig Phosphate-Montney 150

Town Montney 150

Deep Basin Cadomin 150

Deep Basin Nikanassin 150

6 AOF Regulations

Section 63 – Gas Well Tests:

63 (1) Subject to subsection (3), before 6 months have elapsed after a permit

holder has first placed a gas well on production, the permit holder must flow

test the well and determine the absolute open flow potential if

(a) the well is producing from a pool with suspected water drive, or

(b) the well is classified as an exploratory outpost well or exploratory

wildcat well.

(2) A permit holder must submit to the commission, within 60 days of the date

on which the operation concluded, a detailed report of

(a) any gas well flow test,

(b) any cleanup flow that results in burnable gas to the surface, and

(c) any underbalanced drilling that results in burnable gas to the surface.

(3) Subsection (1) does not apply with respect to a well completed in an

unconventional zone listed in Schedule 2.

Well Testing and Reporting – Pressure Tests

• Static Gradient (SG) • requires sufficient shut-in time

• recommend leaving gauges on

bottom stop for 30-60 minutes

to verify stable pressure

• Acoustic Well Sound (AWS) • used on oil wells

• may be single or multi shot (to confirm

static conditions or as build-up)

• Cullender & Smith (CS) • surface pressure

measurements

• valid for dry gas wells

• not accepted for initial pressure

• Diagnostic Fracture Fall-Off

(DFFO) • performed under injection conditions

• often requires pressure transient

analysis (PTA)

• Pressure Gauge (PG) • bottom hole pressure

measurements

• build-up or fall-off tests

• often requires pressure

transient analysis (PTA)

• Drill Stem Test (DST) • okay for initial pressure if valid

8 PST Test Types

9 Reservoir Pressure Survey Test (PST) Report Form

• Each pressure test submitted

requires a completed “PST

Report form”

• download form and

instructions off the OGC

website

• A complete PST package

should include:

• raw pressure data

• PTA analysis (where req’d)

• details of all reservoir pressure

calculations including

extrapolations, assumptions,

etc.

10 Common PST Questions/Errors

• Shut-in time must be reported! If SI time not listed on wireline report, please

determine. “N/A” or “EXT” are not valid SI times!

• Only require one (complete) hardcopy of each PST package to be submitted to

the Victoria office.

• If a SG immediately follows a build-up test, it is not necessary to submit two PST

summary forms. All data can be included on one PST form.

• It’s not necessary to extrapolate pressure data from recorder RD to MPP, but it’s

ok if you do.

• For directional or horizontal wells, please report run depths in true vertical depth

(TVD). Watch the depth units... TVD or MD depths are often misquoted on

wireline reports.

• Please use the ‘Comments’ box on the PST Summary Form to convey additional

information which is useful in understanding the data.

“The BC Way”

OGC does not use a defined ‘maximum rate of pressure increase

(kPa/hr)’ in its determination of a stabilized pressure test.

OGC does not define the required length of shut-in time for

pressure tests.

11 Wellbore & Formation Gradients

Gas:

Oil:

Water:

Typical Fluid Gradients

0.02 – 2.5 kPa/m

5.2 – 8.5 kPa/m

9.8 – 12.5 kPa/m

9 8 1 6 5

** Please report gradients that are representative of the actual fluid!

12 Non-Representative Wellbore Gradients

When a change in gradient data is seen on a

SG test, it is often indicative of a liquid level

encountered in the wellbore.

However this gradient information may not be

not be ‘representative’ of the liquid, as in this

example.

In this case, use best judgement to determine

the type of liquid (utilizing production data, test

notes, history of well, etc) and report the

‘appropriate gradient’ as the wellbore gradient

on the PST summary form.

For example, water would be ~ 9.8 kPa/m and

oil estimated with 7.5 kPa/m.

However, be careful of “Bottom-Up” static

gradient tests as these can report ‘odd’

gradient data on the bottom stop.

Remember to re-calculate LL based on the

appropriate gradients.

Example #1 - Gas reservoir with non-representative wellbore gradient:

13 Uncertain Formation Gradients

Formation gradients represent the ‘primary’

produced fluid (gas, oil) from a zone.

Although not directly measured, SG data

collected within the wellbore can often be

used to determine the formation gradient.

To estimate a formation gradient where

wellbore gradient data is not representative of

the formation fluid (as in this example):

1) Use previous well test data if

available

2) Use offsetting well data from the same

pool, or

3) For gas formations, use data from the

Estimated Gas Gradients by Pressure

Range Table (available on our website).

For oil wells, assume 7.5kPa/m.

Example #1 - Gas reservoir but no gas gradient seen on SG test:

14 Data Quality

Pressures are used for pool mapping, well classification,

and reserves. The 2012 Regulation changes for the

unconventional areas greatly reduces pressure testing

requirements. Quality of testing is replacing quantity.

Accurate testing and reporting is important. Collecting

quality data is our goal.

Well Testing and Reporting – Flow Tests

• Single Point (SP)

• Flow after Flow (FAF)

• Multi Point (MP)

• Clean Up (CU)*

• 4 Point Modified

Isochronal (FMPI)

• Under Balanced Drilling*

16 AOF Test Types

17 Well Deliverability Test Report Form

• Each stand-alone flow test

submitted requires a completed

“Well Deliverability Test Report

form”

• download form and instructions off

the OGC website

• A complete package should

include:

• complete set of field notes (or daily

production notes for in-line tests)

• AOF calculations (for exploratory and

water drive wells only)

• Sandface & Wellhead

• Extended & Stabilized Rates

• gas analysis

• raw pressure data

• PTA analysis (where req’d)

• completed PST report form

18 Common AOF Questions/Errors

• AOF tests are for gas wells only and only if the well is producing from a pool with

suspected waterdrive or for wells classified as Exploratory Outpost or Exploratory

Wildcat.

• An AOF test is required within six months of a well being placed on initial

production. That does not (necessarily) mean within six producing months.

Once a well reports initial production, the ‘clock is running’.

• In-line flow testing acceptable, avoids flaring.

• If submitting an in-line flow test, please report only recent cumulative production

for zone.

• Please indicate if gas produced during test was flared or conserved by checking

the appropriate box on the Deliverability form!

• Single point tests acceptable, prefer multi-point

• For low productivity zones, typically < 20 e3m3/d, then wellhead AOF only is

sufficient.

• Remember to include a copy of the field notes (or corresponding production data

for in-line flows)

• Must report all well deliverability tests.

19 Clean-Up Flows

• For stand-alone clean-up flows where gas flaring occurs,

report volumes and rates on Deliverability form, noting it as a

“CU” TEST TYPE

• If clean-up is immediately prior to and part of AOF test, do not

submit separate Deliverability form. Simply include clean up

volumes and report rates as a “CU” RATE

20 Underbalanced Drilling

• For underbalanced drilling with significant gas flaring, please

submit a copy of the drilling field notes and a “Deliverability

Report Form” indicating test type as “UBD”.

• On the form note only the NET gas rates and volumes

produced during drilling.

Annual Pool Pressure Survey

22 Minimum Annual Pressure Test Requirements

• Minimum number of annual pressure tests for a(n):

• Gas Pool = 25% of total wells in pool or,

50% of producing wells

(whichever is less)

• Oil Pool = 25% of producing wells in pool

*These percentages represent a policy guideline only. In some cases a lesser number of tests

may be adequate, and staff may be consulted on individual cases.

*Unconventional wells in Schedule 2 areas do not require annual pressure testing.

*For all other pools, the OGC ‘rounds up’ to the next whole number when calculating the

minimum number of pressure tests required. This means that single well pools need to be

tested annually unless otherwise approved.

23 Annual Pressure Survey Tips

Select wells that offer good pool coverage.

Plant shutdowns are an excellent time to collect annual pressure

survey data, often facilitating adequate SI time and no lost

production.

Suspended wells are also good test candidates.

Annual testing applies within the calendar year.

Initial pressure tests for development wells can be applied to the

minimum annual pool testing requirements.

The OGC may order additional tests other than the outlined

minimum.

24 Modification of Initial or Annual Pool Pressure Test Requirements

Where adequate pressure history exists, wells have low productivity, and/or there are few remaining

reserves in a pool, exemption from initial pressure testing or annual pressure testing of a pool may

be granted.

The assigned coordinating operator of a pool

may apply to have the annual pressure testing

requirement modified for that pool.

A list of assigned coordinating operators is

available on our website.

A modified testing interval of two or more years,

or a total exemption, may be granted.

The operator must provide sufficient

information to substantiate their request for

modification.

An application guideline is available on our

website as a reference.

25 What Pools Require Testing This Year?

Is the pool producing?

Pressure survey

NOT required.

Is the pool listed in:

“Pools with Non-Annual Pressure

Survey Approval (Table 1)*”? (* available from the OGC website)

Annual pressure

survey required.

Table will specify either:

a) the frequency of testing & which

calendar year the next tests are due or,

b) that the pool is exempt from annual

pressure testing.

no yes

no yes

26 Pools with Non-Annual Pressure Survey Approval (Table 1)

• This image is

page 1 of 5.

Please see our

website for the

complete table.

27 Coordinating Operators (Table 2)

‘Coordinating Operators’ have been

assigned to certain large multi-

operator pools for the purpose of

assisting in the collection of annual

pressure survey data. These

operators draft the testing schedule

for the pools but individual operators

are still responsible for ensuring

testing requirements are met. This

table can be found on our website.

Website Orientation

http://www.bcogc.ca/

Questions?

Please contact: Melanie McKinnon

Well Test Analyst

(250) 419-4433

melanie.mckinnon@bcogc.ca

…or visit

www.bcogc.ca