Record No. 1969 /50

Observation No.1 Special Core Analysis Tests on

Samples from the (8asal Cretaceous)

Birdrong Formation

by

B.A. Mckay

...

BUREAU OF MINERAL RESOURCES, GEOL~Y AND GEOPHYSICS MmERAL RESOURCES BRANCH

PETROLEUM TECHNOLOGY SECTION

1969/50

OBSERVATION NO.1

SPECIAL CORE ANALYSIS TESTS ON SAMPLES FROM THE (BASAL CRETACEOUS~ BIRDRONG

FORMATION

by

B.A. McKay

OBSERVATIon NO .. 1

SPECIAL CORE ANALYSIS TESTS ON COm: SAMPLES FROI\'I TilE (BASAL CRETACEOUS) BIRDRONG FORllTATION.

INTRODUCTIOH

Observation No. 1 (FE 260H) was one of a series of '\7ells drilled by West Australia Petroleum Pty_ Ltd. on various islands in the Exmouth Gulf area, Western Australia, to obtain more information on the stratigraphy and hydrocarbon potential of the off~shore portion of the Carnarvon Basin.

The well was spudded-in on 31st December, 1967. It penetrated Tertiary, Cretaceous and Triassic formations down to the total. drilled depth of 7,510 feet.

Hydrocarbon shows were encountered below 3,000 feet in the basal·· eretaceous Birdrong Formation. These wel;'e drill-stem tested, but no hydro­carbon production was obtained.

The following report presents the results of the analysis tests, (porosity, permeability, capillary pressure, pore size dist7"ibution), and formation damage/repair tests 01 five samples from the 3024t 3032' interval in the Birclrong Formation. There tests were conducted in an attempt to resolve the lack of hydrocarbon productivity in this interval.

PROCEDURE AND APPARATUS

Two separate sets of core samples were used in the tests - five !~inch diameter plugs for capillary pressure and pore size distribution tests and five adjacent plugs ... 1.g.-inch diameter)for porosity, perf.leal~i,lity and formation damage/repair tests. These plugs were trimmed to approx~ 1! inches in length, and dried in an oven at 110oCfor 48 hours.

When the samples had cooled sufficiently, porosity was measured on each of the plugs in a Ruska-type mercury porosimeter, and permeability with respect to nitrogen in a rubber-sleeved Hassler cell. Sub3equently, eauivalent liquid permeability was evaluated in the Hassler cell using the 1i-inch diameter plugs. Using nitrogen as the flowing phase, the permea~ bility of each sample was measured at several (four) different mean, bu~ constant differential pressures. These permeability values for each sample were then plotted as a function of the reciprocal mean pressure, giving the non-reactive liquid permeability.

Single-phase liquid flow tests were then performed on each of the samples to determine their compatibility with fresh water and 1.5% NaCI brine. Each of these tests was preceded by extraction and drying of the samples.

2.

Subsequent to the tests with the 1.5% NaCl brine, each of the samples was flushed with Soltrol-C oil to residual brine saturation~ upon which permeability to Soltrol was determined. Formation damage and repair tests (simulating mud filtrate invasion around the well bore followed b,y subsequent improvement due to oil production) were evaluated by a fresh-water flood to residual oil saturation, then flooding with oil to residual invasion water saturation. Permeability to each fiooding phase was determined after production of the displaced phase had ceased in the effluent stream.

Mercur,y injection capillary pressure tests, following a method by Purcell (Petroleum Transactions, A.I.M.E., 1949) were then conducted on the set of!-inch diameter plugs, in a Ruska-type mercucy injection apparatus. Upon extensive evacuation, each of the samples was subjected to an increasing mercury pressure, and the volume of mercury injected at each pressure step. was measured.

To obtain hysteresis capillary imbibition or withdrawal curves, the pressure in each sample was reduced in steps from 1500 to 0 psia. After correction for mercury surface conformance and p~p expansion had been made, two curves, the injection and the withdrawal, were plotted for each sample.

Pore size distribution values were obtained from the mercury inject­ion curves, using the formula r = 2.1:9.08.'1 where r=the pore thrqat radius in microns, and r,ll9respectively equalt'h~P. illercury surface tensiOn and contact angl~ of mercury with the solid, and~ 'being the differential injection pressure at the respective saturation intervals.

DISCUSSION

The data for the porosity, permeability,' single and two~phase flow tests are presented in Table 1. . Capillary pressure curves for each of the' samples are shown in Figures 1-5; the corresponding pore size distribution results are listed in Table 2. The Klinkenberg or non-reactive liquid perm-' eability tests are shown in Figure 6, while the position of the 5 samples is shown in Figure 7.

The resui ts of the single-phase liquid permeability tests to fresh water and brine, shown in Table 1 generally indicate very poor coriipatibili ty between the rock (samples) and an aqueous phase. The flow capacity in these tests varied froPl a maximum of 64% to a minimum of 1. 'do of equivalent liquid permeability when brine and fresh water were respectively used as the saturat-ion and flowing media. !: I

The most severe·-reduction of flow capacity was noted in samples from 3024, 3026, and 3028 feet. The effluents during flow tests on these tf:iree plugs were very cloudy, indicating a considerable amount of particle dis­placement. However, v~ations in flow capacity when using fresh water and brine were not great, indicating a minimal content ofswe~ling clays.

.:.

3.

Even more severe formation damage is indicated under twouphase flow conditions. In the case of a well bore invaded with mud filtrate (fresh water flood) reductions in permeability in excess of 99% at residual oil saturation were noted. Flow capacity was partially restored by the re­flushing of the water-invaded cores with oil; however the results indicate a con8i0p.rable time is required to restore permeability to anywhere near its former value.

The mercury injection capillary pressure curves indicate the five samples from this interval to have low threshold pressures and low indicated water saturations at ultimate test pressure. The largest pore throat radii invaded at entry pressures ranged from 12 to 26 microns. The mercury withdrawal curves, simulate t11;e hydrocarbon producing characteristics of this reservoir by imbibition, whereby a wetting phase (air) displaces a non-wetting phase (mercury). These tests indicate hydrocarbon recoveries up to 35% of pore volume; the highest recovery occurring in the "cleaner" sands below 3030 feet.

The core analysis reports, 1 (a), (b), (c), for this interval indicate residual oil saturations of up to 16% of pore volume, and water saturations between 55% and 80% of pore volume. A drill stem test of the interval produced 38 barrels of saline water only.

Porosity, permeability and capillary pressure characteristics of this formation suggest that this interval could be hydrocarbon productive. However, the "borderline" residual oil saturations determined in routine co~e analysis, plus the strong probability of formation damage occurring around the wellbore, ·as shown in this report, tend to confirm the negative drillstem test results.

CONCLUSIONS

~he tests revealed the interval under consideration to have some good reservoir characteristics; both porosity and permeability (to nitrogen) were high, while capillary pressure characteristics showed low threshold pressures and low indicated residual water saturations.

However, single and two-phase flow tests using fresh water} brine and oil revealed this formation to be highly subject to permeability damage. Simulated fresh water invasion tests surrounding a well bore, showed permeability reductions greater than 99%. Permeability was only partially restored through resaturation and lengthy flushing with oil •

1 (a)

(c)

.. Exploration Logging of Australia Inc., Core Analysis Report, January 10, 1968.

(In the Well Completion Report)

Core Laboratories Inc., Core Analysis Report, January 18, 1968. (In the Well Completion Report)

Bureau of Mineral Resources Petroleum Technology Section Core Analysis Report, January 17, 1969.

ample Porosity epth (X Bulk Feet). Volume)

Permeability to Ni trogen

(rlid·) . \

Tab 1e 1.

-~::~~:~:nt-- ~:~::ab~~~~-- p:~::::~~~~~--)--::~::::~~~~~----------Liquid to Fresh to 1.5% to Soltrol-c

~ermeability • Water ~%E.L.P* Nac1 Srlne at Kesidual (Md) . . (% t.l.P.*) Brine

Saturat Ion (% E.L.~*)

------- -------- ------------ ------------!t--...,.------- ---- -.Jo----------------3024 33.0 491 412 2.4 26 23

------------------------------------------4 FORMATION DAMAGE AND REPAIR TESTS

-permeabll1ty--l~permeabiilty-to-O'i-at---to Fresh water Terminal Fresh \IJater at Residual 011 . (% E.L.~.*) ~aturati on (t E.L.P.*) -'~med'a~ After-Z4-Hours

.04 4.2 20

------- --------- ----------- ----.-------- ------------- ------------ ----------------------- --------------- ----------- -------,~~

3026 29.7 1125 990 1.2 8.8 SAMPLE BROKEN U?

-------- --------- ------ ._+-------- --------------------- --------------- --------- ------------3028 33.0 489 445 7.9 20 16 .36 3.0 13

---------~ ------------- ---------- -:------------3030 22.0 116 95 24 53 11 37 37

-------- ------~------ ------------- -------------_. ------------- -------------------------- -------------- ----------- -------------3032 24.5 710 660 4.4 28 24 4.1 27 28

------- --------- -------- --------- ~ --.---------- ------- -------------- ---------

* E.l.P. = Equlvalent lIquId Permeablllty.

Tabl'e 2.

-

SATURATION (% PORE VOL~) Sample

Depth

10-20 l (Feet)

0-10 20-30 30-40 40-50 50-60 60-7Q 70·~80 "

, - -

12.5 9.7 7.9 5.9 4.4 3.1 1.4 0.46 3024 .-

~-- 14.2 11.5 9.7 7.2 5.6 2.0 0.19 3026 800

~§ ~~ 11.2 9.7 7.6 5.6, . , ., 2.7 0.63 ,3028 o~ Poi .......,

§OO «I:: 17.2 15.2 12.9 10.7. 6.9 3.0 0.71 o. "17 3030

~~ 26.6 22.2 19.5 12.5 7.1 . , . 2.8 0.82 0.19 3032 <.

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