Evaluating Seal Facies Permeability and Fluid Content from Drill-Stem Test Data, R.C

Home , Drill stem test

Reid, H.W., 1997, Evaluating seal facies permeability and fluid content from drill-stem test data, R.C. Surdam, ed., Seals, traps, and the petroleumin sys tem: AAPG Memoir 67, 299-312. p. Appendix

Evaluating Seal Facies Permeability and Fluid Content from Drill-Stem Test Data

H.W. Reid Hugh W. Reid & Associates, Ltd. Calgary, Alberta, Canada

ABSTRACT Many facies assumed to act as seals contain stringers of sand and silt that are potential low-grade reservoir units. The drill-stem tests (DSTs) from these formations generally show them to be "tight," but many of the wells in these "barrier" facies ultimately become commercial producers after comple tion. Calculation of the permeability and fluid content of these facies from DSTs has not been a common practice because the facies often do not pro duce oil or gas when tested, making them unattractive to operators, and because the analysis of DSTs from tight formations can be problematic. However, knowing the permeability of seal facies helps operators determine which of these "barriers" are the leakiest and, hence, are the best potential exploration targets. In this study, the shape of the shut-in curve on pressure charts and other subtle indications are used to more accurately assess the reservoir quality of these neglected formations. This paper will attempt to demonstrate that a good approximation of the leakage potential of these facies can be made using published empirical correlations if the permeabili ty, as from a DST, is known.

INTRODUCTION Estimation of permeabilities of reservoir-quality rocks from DSTs are performed routinely, particularly In many pinch-outs, lateral seals are not perfectly if hydrocarbons were produced during a test. How solid shale; stringers of low permeability sand and silt ever, the permeabilities of tighter barrier or seal facies exist and are often oil stained (Figure IA). If a well has of traps are rarely computed from DSTs. This is "missed the sand" and penetrated the barrier, it is not because (1) operators are generally not interested in likely to be cored. But any small stringer with a show further investigation of unsuccessful tests from dry is often subjected to drill-stem test (DST) pressure holes and (2) there are many perceived difficulties in buildup analysis before abandoning, just to be sure it performing DSTs in tight formations where the pres does not contain potential pay (Figure IB); the leakiest sure curves are not sufficiently stabilized for standard stringer in a barrier controls the trap holding capacity. Horner-type analyses. Several methods of analyzing For this reason, many DSTs of "tight" barrier facies tight DSTs are currently used by DST service compa exist. These data are important because they can be nies and usually involve the use of proprietary soft used to determine permeability, fluid content, and ware, but good approximation of permeability I leakage potential within a barrier facies. thickness (kh) can also be made using simpler "type

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DST 1 Rec.Gas Cut Mud

B Figure 1. (A) Diagram of a typical sandstone pinch-out into a barrier facies; inset shows interbedded sands in a lateral seal. (displacement pressure) is Pd not directly proportional to K (permeability). It is also related to pore size dis tribution (Burdine 1950). (B) Diagram showing missed potenti l pay in a bar , a rier facies. After Hill et al. (1961).

curves" designed specifically for DSTs (Crawford et produced on test. (The hydrocarbon presence may be aJ., 1977). inferred from the configuration of the shut-in pres Useful information is often extracted from even sure curve and other subtle indications.) In fact, the tightest DSTs. For example, the presence of resid many times, a minor quantity of hydrocarbon is ual nonhydrocarbons in the silty barrier facies, produced from the tight sandstones; thus, the perme updip from reservoir pinch-outs, may be detected ability calculated from the DST is actually the perme from "mud recovery OSTs," even if no oil or gas was ability effective to the hydrocarbon phase. Since we

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Shut-in pressures Minor mud recoveries show negligible rise Air blows only "fype A Ty pe A 1 ' Rec. < 00' mud I no gas to surface \ I! 1 I \ \ I Strong I \ \ I I I \ Seal \ I ' I llu \ I \ ------= -----::c�,.c.=- --- ' Extremely Tight Zo Flow curves areL Negligible kh �virtually horizontal kh s 0.1 md ft kh s 0.1 md ft

Very slow rise in U Minor mud recoveries B shut-in pressure t'r1 Ty pe s Ty pe B 1 G.T.S. TSTM or < I � ' Rec. < SOO' Iiquid <50 Mscf/0 � I 1 mud, oil or water Fair I \ = \ \ I I I \ � \ \ to Weak I I \ s· \ OCI I \ \ \ I h! Seal \ \ [JJ I ' I < \ It> Ve ry Low kh � Imperceptible rise � Very Low kh in flow pressure � kh = 0.1 to 10mdft kh = 0.1 to 10 mdft � ,.,..,. U .... Fairly rapid rise Measurable gas rates It>rJ> Ty pe in shut in pressures Ty pe >500 Mscf/0 '"d C but static value Rec. 500' C Some mud or condensate It> I I. to 1 000' liquid 9 j/ \ not reached I \ \ recovered I \ 1 It> \ / ' I \ 1 ;::? \ / ' I \ �lV ' w I \ / �� -, ' 1 \, 1 I� -<" Low to Moderate kh �Flow curves show Moderate to good kh � appreciable rise Normal Q.. kh = 1 to 1 00 md It kh = 0 to 1 00 md ft .., Reservoir 1 - Shut-in pressures Quality Gas rates over 0:= ' Ty pe D stabilize almost , Ty pe D 2 Msct/o ' Rec. > 1 000' liquid n immediately / Usually only minor liquid 0 {r - \ 1 � ' , coproduced unless It>= I \ I ' very wet gas - I \ I I '""= / \ ' .... I � I \ I ' I ' I 0 � s High to Excellent kh � Flow curve rises High kh rapidly and almost 0 kh � 1 00 md ft reaches shut in :::!.' Y pressure value [JJ::= - It> s Figure 2. Model pressure charts showing an example of a liquid and a gas test for each of the following: strong seal rocks, fair to weak seal rocks, It>...., rJ> and normal reservoir-quality rocks. Msd/D= thousand standard cubic feet per day. - 0

�

w 0 ......

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values, in turn, the approximate trap holding capacity Location may be estimated for the nonleaky barriers. These data INSIDE REC. have important implications; if a leak-prone seal is Depth known to contain residual oil, this may warrant mov #6-23-46-7 W4 1 ing updip to find the reservoir. DST#2 In addition, deep formation damage often leads to a #8849 distortion of the shape of the DST shut-in pressure 582.8 curve, so that the DST looks tight, but in reality is not. In fact, in some so-called tight tests in "barrier" facies, I the wells tested ultimately became commercial pro ducers after completion. Preexisting maps of the l "trap" have had to be changed somewhat, such that the reservoir was enlarged and the "trapping" facies shrank! Such a situation is not always unrewarding for the geologist, who does not have a seal, but may have kh = md ft just discovered potential missed pay to redrill. Thus, a Over ft sand :. K = md DST may reveal that the barrier facies is not a seal at all but a potential low-grade reservoir. Figure0.4 3. Field example of a weak seal updip from the Viking/Kinsella5.5 gas0.07 field, southern Alberta. RELIABILITY OF PERMEABILITY MEASUREMENTS DERIVED FROM DRILL-STEM TESTS are interested in the potential for hydrocarbon leak age, not water leakage, the tight hydrocarbon tests In order to gain a qualitative estimate of permeabil provide the most direct tool for this assessment. Once ity /thickness, kh, and hence indirectly the leakage the permeability effective to the hydrocarbon phase is potential of the facies, and seal capacity, Pd, from DSTs, known, a range of possible displacement pressures can model pressure charts are shown (Figure 2). An exam be estimated from empirical correlations. From these ple of a liquid test and a gas test is shown for each of

B ------. I.S.I.P F. S.I.P 1910 psi 1765 psi

F.F.P psi 350base line initial !1t1 flow --tl.tz� --tl.t3- --tl.t4-- �tl.ts- �---.!1t6-. 1------otl.ty---1 1------.t1t8---�1 1------tl.tg----1

Figure 4. Analysis of a DST using the Homer Method; the chart is measured in detailed pressure/time increments.

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2000 Poorly developed curves -- - ao 1910 f------:,_-:;. not suitable for standard 1800 ------"" 1600 Sl -- ;v--- b -- 1536 1--' �/ en 1400 Straight line portion 1910 1536 3: / "M" = 37 4 - 1200 ./ = psi/cycle a_ v 1000 / Figure 6. Example of a DST of a tight seal showing 800 how the shut-in curve is not sufficiently built up to reach the "straight-line" portion needed to compute kh using the Homer method. SI = shut-in. 10 8 6 4 2 l=�t �t seal (type B test), contains gas, and may presently be Figure 5. Homer Plot constructed from a DST. leaking gas (Figure 3). These results are confirmed by

service company computations of kh = 0.4 md ft. and

>5.5 ft of sand, indicating k = 0.07 md.

the following: rocks that constitute strong seals (type A The Homer Method tests), rocks that constitute fair to weak seals (type B The Horner Method can be used to compute a tests), and rocks of normal reservoir quality (type C quantitative kh value from a DST. The Horner Method and D tests) (Figure 2). A field example (Figure 3) proceeds as follows: from a barrier facies updip of the Viking /Kinsellagas field in southern Alberta, Canada, is also shown; • A chart is read in detailed pressure I time incre (Cretaceous Viking Sand) pattern recognition indi ments (Figure 4).

cates that the field example constitutes a fair to weak • A Horner Plot is constructed (Figure 5).

Core Figure 7. Saturation of area in kabsolute DST drainage radius. 1 . O

0.9

> 0.8 ."'!::: = X :.0 DST ke kro k8 - --+------A0.7 Q)co

E..__ 0.6 Q) 0.5 0... Q) 0.4 -�+-'

keffective = co 0.3 Q)..__ kabsolute X krelative .::i 0.2 0.1

0. 0 L-..J._--l----4H-e:::::.:L...----'--.I...... - ..... 0.0 0.1 0.2 0. 0.4 0.5 0.6 0.7 .....0.8 0. ----J water saturation, fraction Sw, I

Saturation of area in DSTdra inage ra dius

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1.0 CHART FROM FIRST TEST ON PENETRATION (GAS FLOW Mscf/D)

Reduction of K by an order 0_ 1 INVASIONI of magnitudei"'m�e----f....-c------11. with t 45 appears moderate khbut evidence of damage � & DAMAGE :0 � 0.01 I BECOMING ....E (]) I a.. CHART FROM SECOND TEST 31 DAYS LATER 0.001 WORSE (SAME INTERVA L; GAS FLOW T. S.T.M.) -�- I a;ctl a: WITH appears very low 0.0001 I ' khno evidence of damage Ij , TIME \ I j llfi'\\._ __ _ 0. 00001 L....--1--'---L-'--+...______. ! 0.3 0.4 0.5 0.6 0.7_ __.__ 0.8 0.9...... _ ___.1.0 e Wat r Saturation Figure 9. Drill-stem test charts from a Triassic sand I in northeast British Columbia; first test completed 35% Sw after 58% Sw on penetration, second test taken 31 days later. penetra tion when tested by drill bit after 1 week with time. In the chart from the first test on penetra Figure 8. Relative permeability change in a low tion (gas flow 45 Mscf/0) of a Triassic sand in north permeability gas zone tested one week after drilling. east British Columbia (well location: 94-G-1-89-0), kh appears to be moderate, but there is evidence of dam If a straight line develops, the slope is determined age (Figure 9). In the chart from the second test 31 • days later in the same interval (gas flow too small to and kh (if liquid) is computed as measure), kh appears very low, and there is no evi dence of damage (Figure 9). Thus, a OST is simply a 162.6(q)(J1)({3) "snapshot in time" of a changing kh, so one should kh = m test upon penetration to obtain an accurate kh.

where q = flow rate in s.t.b./d (stock tank barrels per DETERMINING FLUID CONTENT AND day), J1 = fluid viscosity in cp, f3= the formation vol ume factor in r.b./s.t.b (reservoir barrels/stock tank 11SUBTLE" OIL IN SEALS barrels) and m = slope of the Horner Plot psi/cycle. A Fluid Content slightly altered formula is used for gas OSTs. This method is really not suitable for OSTs of "tight" seals Even though drill-stem tests (OSTs) of tight barri because the shut-in curve is not sufficiently built up to ers usually only produce mud, we can frequently reach the "straight-line" portion necessary for this determine if hydrocarbons are present from the technique (Figure 6). However, OST data can be ana shape of the shut-in curves in the pressure chart. So lyzed using Type Curve Analysis (Crawford et al., far we have seen that permeability affects chart 1977). shape, but thus far in all cases normal shut-in curves There are certain advantages and disadvantages to have an ever-decreasing slope, regardless of the calculating permeability measurements from OST data effects of permeability (Figure 10). The pressure rather than from core data. OST values are frequently change (dPjdT) is directly proportional to the flow

less optimistic and more realistic than core-derived rate (q): dP/dT oc q (where single-phase fluid is pro numbers because a OST-derived permeability is an in duced). Thus, as the well "slows down" on closing situ value and is a permeability effective to the fluid the valve, the shut-in pressure slope decelerates. produced at the saturation that existed around the This ever-decreasing slope (dP/dT) (Figure 11) exists well bore during the test (i.e., at reservoir saturation) because downhole, after the valve is closed the well (Figure 7). However, if deep invasion occurs, such as "slows down," but still flows into the space below in this example of a low-permeability gas zone tested the packer and closed valve (Figure 12). In most one week after drilling (Figure 8), the OST-derived shut-in periods, there is ever-decreasing flow into a permeability may be pessimistic. It is clear from this closed volume. field example from a Triassic sand in northeastern However, some shut-in curves are not ever British Columbia (Figure 9) that kh values can change decreasing slopes. Sometimes a constant slope (type

The shut-in curves Figure 10. Pressure charts display ever- showing that usually shut-in 'eas;ng slope curves have an ever-decreasing slope. Permeability Type d Excellent

FSI 2nd lSI '- 1st flow flow

Good

FSI 2nd lSI " 1st flow flow

Relatively low

FSI 2nd lSI " 1st flow flow

Very poor

FSI 2nd lSI " 1st flow flow

A curve) will result from severe shallow damage or "Subtle" Oil in Seals deep formation damage (Figure 13). An 5-shaped curve results either when two phases are present in An 5 curve indicates that oil is potentially present the formation or in the case of gas zone cleanup in the reservoir because of the pore geometry and (Figure 13). Thus, even if only mud is produced by relative permeability problems encountered during the DSTs, the shape of the shut-in pressure curve testing. The early acceleration and subsequent decel can often reveal whether hydrocarbons are present eration of the 5 shape result from gas blocking pore in the rock. throat spaces and then going back to solution, which

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TOOL SCHEMATIC Ever-decreasing slope \�

Figure 11. Field example shut-in curve with an ever decreasing slope.

distorts the shut-in curve. More specifically, an 5 Bypass valve closed curve develops as follows (Figure 14). Before the tool is opened, mud pressure in the annulus exceeds the saturation pressure of the oil, so all of the gas remains dissolved in the oil. After the tool is opened, the reservoir is exposed to the atmosphere, so gas breaks out suddenly in the oil, in the pores, and in the pore throats. In severe cases, if gas breaks out in Sump narrow pore throats, it breaks the connecting oil fila In most shut-in periods Volume ment, blocking the oil flow ("gas block") and causing there is ever-decreasing (Rat hole relative permeability problems. Gas flows preferen flow into a closed volume tially, but often at a negligible rate. Finally, during plus internal the shut-in periods, as the pressure rises over the tool volume) bubble point, most gas is redissolved or is in a very compressed state, and the shut-in curve resumes its usual deceleration. The 5-curve DSTs are common in tight barrier facies because the 5 shape is more pro nounced in lower kh rock. Figure 15 shows a range of 5 curves; the 5 shape becomes more pronounced as Figure 12. Tool schematic showing how in most permeability decreases. shut-in periods, there is ever-decreasing flow into a closed volume. ONE MAN'S SEAL MAY BE ANOTHER MAN'S RESERVOIR! (CASE HISTORIES) The cumulative production of this well over 17 years was 9985 s.t.b. oil, 2850 s.t.b. water, and 41.5 Case 1: Economics (Northern Alberta) Mscf of gas. While this well is not economically viable in Alberta, it might be commercially productive as a There are two cases in which a barrier updip may stripper well in the eastern United States (depending actually contain a producible reservoir (Almon and on the oil location and the price of oil). These findings Reid, 1990). The first case is when low-grade silt/ are typical of many such tests of poor-quality stringers sand developments in barriers updip often can pro in barriers that can be considered reservoir rocks. If we duce marginal oil wells that are economic if the take into account that the average U.S. oil well rate is price of oil rises. Figure 16 is a typical, very poor only 14 bbl/d and the average Canadian oil well rate looking DST from northern Alberta with develop is 40 bbl/ d (Society of Petroleum Engineers, 1988), the ment of only one part of the 5 curve. Despite disap importance of such stringers is evident. pointing recovery, the subtle 5 shape indicated that oil could be present in this barrier. In order to test Case 2: Cinderella Story (North Dakota) this hypothesis, the operator stimulated the well in The second case in which a barrier acts as a reser the following manner: voir rock occurs when a high kh zone is mistakenly perceived to be tight, but actually contains commer • Treatment: 500 gal acid; fractured 15,000 lb sand cially viable reservoirs. The DST from this zone (Fig gel &XW ure 17) is similar to that of Case 1, and has a poorly • Initial production: 33 bbl/ d (barrels of oil per day) developed 5 curve. The Horner Plot also indicates

Figure 13. Shut-in curves that do not have ever-decreasing slopes. Causes The type A curve has a con Ty pe A stant slope and results from Severe 'shallow' severe shallow damage or Constant slopes damage or deep formation damage. 'deep' damage The type B curve has an S shaped slope and results from the presence of two phases in the reservoir or in Ever decreasing the case of gas zone slope, cleanup.

Causes Ty pe B Two phases 'S' shaped slopes present or Gas zone cleanup (usually oil)

Ever-increasing slope

that the formation is tight and not of reservoir qual initial production of 408 bbl/ d (85% oil) was clearly ity (Figure 18). However, sample examination shows economic. Based on this and similar examples, it is that the unit has big pores and very small pore advisable when dealing with a tight 5 curve on a throats, conditions that are ideal for gas block (Figure DST to look at the pore geometry before assuming 19). In addition, the Pitman diagram (Figure 20) shows the reservoir has been missed, and to consider isolated large pores connected by tiny micropores. using a gas cushion above saturation pressure on a While many pore throats are only 0.02 and represent retest to prevent gas block in the oil in the pore micropore throats in the matrix, some poreJ.1 throats are space immediately surrounding the well bore. 0.25-0.5 and represent big, intergranular throats (Figure 21).J.1 The ratio of microgranular to intragranu lar pores is 1:1 in the unit matrix (Figure 20). CAUTIONARY NOTES Since the DST indicates the unit is very tight, but we know it has high permeability, some other factor Not all DST charts displaying an 5 curve are must account for the overly pessimistic DST values. indicative of oil. Some can be caused by residual, It is likely that this discrepancy has been caused by nonproducible oil in the tested unit (Figure 24). The gas block; work by Exxon shows that mobile gas sat saturation of these units is such that water would be uration in a case like this is 10%-20% (R.M. McKin produced if they were completed (in 10% of the ley, 1990, personal communication). In fact, the cases, e.g., transition zones). However, these tests relative permeability diagram (Figure 22) indicates indicate that operators are not far from oil; they that the permeability and deliverability values fore should move downdip from a waste zone and updip cast by standard DST computations are two to five from a transition zone in order to locate the oil reser times less than the actual values due to gas block voir. Other tight S-curve DST charts are actually alone (physical well-bore damage can increase this caused by the presence of gas, not oil, in the reser discrepancy as well). voir (Figure 25). Gas-bearing zones can be differenti The difficulty at this point becomes how to stop ated from oil-bearing zones by observing gas rates. gas breakout when retesting the well. In order to If a gas zone is deeply damaged and is "cleaning accomplish this in the example, the flowing pres up," the rates are increasing; as the well is shut in, sure was kept above bubble point by utilizing nitro the pressure change will accelerate also, since dP/dT gen as a cushion. The DST chart of the retest (Figure oc q, yielding the accelerating part of the 5 shape 23) indicates high kh, and the recovery was 713 ft shut-in curve. (217 m) of highly gas-cut oil and 360 ft (110 m) of We can learn about the trapping and the leakage gas-cut saltwater in the unit. The Horner Plot shows potential of the barrier indirectly from a DST. For that kh is 45 md ft. The well was completed, and the example, if we have a DST of a leaky stringer updip

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Rei K Diagram 100 Pore Rock grain

Above Ps _80=0.75

:. Gas Dissolved = Kro 0.6 1.0

____ _ 0.1 .J...L.._ __._ _, 1 s - 75% 100 0

Resumed deceleration DST chart P5 saturation pressure ----· ------

flow Pre- lSI 2nd FSI flow Result: GTS - TSTM Rec. OCM

100

10 Below Ps _ 80 = 0.20 :. Solution Gas Kro = 0.07 Breakout 1.0 but

89 = 0.8 K g = 0.7 r 0.1 ...... __.�...--._____ . ..__, 1 25% s- 100 (75% gas) 0 100 _ s9

Figure 14. Diagram showing the development of an S curve in the case of a test of an oil zone with a pore geometry of big pores and small throats.

of a pinch-out and we know k, we can estimate the (Petroleum Research Corp. A-5, 1959). Using the displacement pressure and from this value estimate chart shown in Figure 27, we enter k as 0.4, then Pd = how much the downdip hydrocarbon height, Z, is in 0.25-1.5 psi. Next, we find the subsurface oil and the reservoir (Figure 26). In order to find the dis water gradients, which in this example are 51° API placement pressure using a DST in a leaky stringer oil at 4000 psi and 160°F = 0.246 psi/ ft, and 200,000 updip of "sure shot" pinch-out, an estimate, of water at psi and 160°F = . 81 psi/ft a n, mg/L 4000 0 4 the pore-size distribution index is made (Burdine et (Petroleum Research Corp., 1960, figures 3,4). al., 1950). Since in this example the lithology is a Finally, we calculate the maximum oil colum11 (ZmaJ silty, dirty sand, will vary between 2.25 and 3.5 that can be supported under these conditions, n

'S' shape more pronounced as permeability Subtle 'S' decreases (good permeability)

Broad sweeping 'S' (lower permeability)

Only part of 'S' developed (apparent poor permeability)

Figure 15. Diagram relating a range of S curves to permeability.

accounting for any variations in interfacial tension, This prospect is unlikely to hold an economic oil which in this case is column unless the hydrodynamics are favorable, p i.e., there is strong downdip flow (e.g., as in the ----"-d 1.5 z max = =7ft Joffre oil field, in the Viking Sand, Alberta), or the Vw-Vo (0.481 - 0.246) leaky stringer is not continuous to the updip edge of the reservoir. (The chart assumes an oil/water inter where Zmax = maximum oil column (ft), Pa = dis facial tension of 10 dynes/ em; since this could vary placement pressure (psi), = subsurface water gra from 3 times (30) to 0.5 times (5.0), Pd and Z also dient (psi/ft), and = subsurfaceV w oil gradient (psi/ft). V 0 vary directly.)

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5168

3520

60 88

1438' REC GAS 120' GAS AND WATER CUT MUD 1100 cc OIL, 1220 cc Rec 55 ft VWIP dead after 15 min. SAMPLE CHAMBERS CONTENTS MUD, DST: mud. 525 1.5 cu It GAS psi

Figure 16. A typical, poor DST with development o.f only one part of the S curve from a marginally pro Figure 17. Another DST with a poorly developed S ductive unit. VWIP = very weak initial puff. curve from a commercially viable reservoir rock. Arrows indicate early accelerating and late deceler ating shut-in curve displaying the S shape.

3500 direction of flow

Horner Plot I I 3000 Too tight for straight I line to be developed I I I 2500 I I - I ·u; small capillary force, I 2000 a...... large pore radius I Q) I ...... I ::J I C/) 19. I 1500 Figure Schematic diagram illustrating large 1 I (/) Fin al Q) pores and small pore throats; these are ideal condi 1 I ...... a.. tions for gas block I I I I I 1000 I Initial; / / I / / / / / REFERENCES CITED / / 500 _., Almon, W. R., and H.W. Reid, 1990, Geology and DST analysis: an integrated approach to identify forma -.--. --.----.------+0 r..-.. 10 7 5 4 3 2 1 tion damage and bypassed pay using pore geome try, clay mineralogy, and pressure behaviour: Time (T Calgary, Canada, Canadian Society of Petroleum + .1t)/�t Geologists, v. 17, p. 1-2. Burdine, N., L.S. Gournay, and P.P. Reichertz, 1950, Figure 18. Horner Plotof the DST shown Figure 17. in Pore size distribution of petroleum reservoir rocks: AIME Petroleum Br. Trans., v. 189, T.P. 2893, p. 195-204. Crawford, G.E., A.E. Pierce, and R.M. McKinley, 1977,

lntergranular 50.0 -,------, Pore Throat Size Distribution

40.0 Q) � Q)g. 30.0 29.3

00. � 20.0 8:� 10.0

0.0 0.00+----;===;-...;=:::==;.---,-..,--....,----i="""'f=:::;..--,-...,-...... ,--,,.....--i 021 .024 .027 .030 .035 .042 .053 .061 .071 .085 .107 0.14 0.21 0.35 0.52 0 Pore throat radius, microns 0 0 0 0 Figure 21. Pore-throat size distribution of the forma tion tested. Microgranular lntragranular

Figure 20. Pitman diagram for the rock tested by the DST shown in Figure 17. DST Chart, Retest

5168 1.0 485 preflow Krg second flow 0.8 high kh - Productivity 286o'------c--2 __.-----/--...,sl buildup 2923 Increase by 93Qi 0.6 0.6---1.6 cushion press 1834 above bubble point '565 � 1 ::.::: 0.4 \ Kro to cushion _/ l bleed-off 440 0.2 -0.2 - 5j -- times RECOV: 713' HIGHLY GAS CUT OIL (if Gas Block 360' GAS CUT SALT WATER 0 removed) 0 20 40 60 80 90 100 HORNER PLOT SHOWS kh = 45 md ft

Liquid saturation (Sw + S0) Figure 23. Drill-stem test chart of the retest, indicat ing that 713 ft (217 m) of recoverable, highly gas-cut Figure 22. Relative permeability diagram for the zone oil and 360 ft (110 m) of gas-cut saltwater are present tested, indicating that the permeability and deliver in the unit. The Horner Plot shows kh = 45 md ft. ability values predicted by standard DST computa tions are two to five times less than the actual values.

Type curves for McKinley analysis of drill-stem text Petroleum Research Corp., 1959, Reservoir pinch data: SPE paper 6754 presented at 52nd Annual Fall outs-sieves or seals?: Denver, Colorado, Researach Conference of SPE of AIME, Denver, Colorado, Oct. Report A-5 (unpublished), September, 58 p. 9-12. Petroleum Research Corp., 1960, Geologic significance Hill, V.G., W.A. Colburn, and J.W. Knight, 1961, of pressure gradients, capillarity, and relative per Reducing oil finding costs by use of hydrodynamic meability: Denver, Colorado, Research Report A-0 evaluations, in Economics of petroleum explo (unpublished), 60 p. ration, development, and property evaluation: New Society of Petroleum Engineers, 1988, Energy focus: Jersey, Prentice Hall, p. 38-69. Journal of Petroleum Technology, v. 40, no. 2, p. 168.

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'S' SHAPED CURVE OF WATER ZONE 'S' SHAPED CURVE OF DAMAGED GAS ZONES (RESIDUAL OIL) -'CLEANING UP'

Recovery: 64 m mud; no gas to surface DST Flow Rate: 12 bbl/d (1.9 m3/d) Post-Completion Rate: Swabbed 'dead' SW 40 bbl/d (6.4 m3/d) Recovery: 1 9 m mud @ DST Flow Rate: Gas flow rate gradually increasing to 25 Mscf/D (700 m3Jd) Figure 24. S-shaped curve of water zone caused by Post-Completion Rate: 1.7 mmscf/d (47x1 03 m3Jd) residual, nonproducible oil in the tested unit. after 5000 gal. acid

Figure 25. S-shaped curve caused by gas in the reser voir, not oil (i.e., damaged gas zone cleaning up).

50.0

10.0

hydrocarbon 5.0 height ""0 (L

1.0

0.5

Figure 26. Forces controlling hydrocarbon height in pinchout-static (not hydrodynamic) conditions. 0.05 0.1 0.5 1.0 5.0 K (md) Figure 27. Chart showing the relationship between displacement pressure, P and rock permeability, K, for various values of d'the pore-size distribu tion index. n,

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Adsorption capacities, 19-20 carbonates AGC. See Automatic gain control Cathodoluminescence, 107 Air permeability, 40 CD. See Craton-derived sediment Alazan-type fields, 257 Cementation, inhibiting processes, 292 Alberta Basin (Canada), 269-280 Cendere field (Turkey), 180 Alberta Foothills belt, 70-72 Clay, 34. See also Diagenesis, clay Allan Map projection, 50 Clayshale, 34-35 Almond Formation, 289, 295 Claystone, 35 sandstone diagenic history, 291-292 Closure, 58, 60, 65-66, 81, 95 Amos Draw field (Wyoming) reservoir, 233 vs. seal strength, 64, 78 Analysis, displaced section (DSA), 135 seal strength and, 67 Ann Mag-type field (Texas), 257, 259 Column, trappable, 58 Aromaticity, carbon, 249 Compaction, 44-45 Arrabury Formation, 146 disequilibrium, 204-206, 218-219 Automatic gain control (AGC), 273, 274 Compartmentalization, 219 Compartment(s). See also Fluid-pressure compartments Barrier updip, 306-307 overpressured shale, 215-216 Basin modeling, 193-195 seals, breached, 216-217 BHT. See Temperatures, bottom-hole underpressured, 217 Biala oil field, 161-162 Condensates, 65 Bioturbation, 91 Conformance, 95 Birkhead Formation Cooper Basin (Australia), 145, 146 bedded shales and siltstones, 154 Core plugs, 15 reservoir, 148-150, 155 Craton-derived (CD) sediment, 143-144 seals, 155-156, 163-164 Cretaceous Mardin Group carbonates. See Mardin Bodalla South oil field (Australia), 150-152 Group carbonates Boliikyayla-Cukurtas oil field (Turkey), 169-172 Cromer Knoll Group, 119, 124 Boyle's Law, 39 Cuttings gas, 130 Broom Formation, 105 Buoyancy, 81 Darcy's Law, 110 Dehydration reactions, 212 Calcite Depth profiles, vs. pressure, 256 adsorption capacities, 20 Diagenesis cementation, 89 clay, 208, 247 Campanian Karadut-Kocali allochthonous unit, 170 sweet spots and, 291-293 Capillaries Dim spots, 269 displacement pressure, 215 Disequilibrium compaction, 204-206, 218-219 entry pressure, 5, 63, 64 Displaced section analysis (DSA), 135 pressure curve, 3 Displacement pressure measurements, 3-5, 103, 107-108 pore throats, 42, 43 permeability, 107-108 pressure, 41, 214-215 properties, 38 Dolomitization, 177-178 sealing of shales, 32 Drill-stem tests (DSTs), 201, 291 seals, 224-225, 250-252 data, 299-310 Cap rocks, 115 S curves and, 307-310 defined, 116 DSA. See Displaced section analysis leakage, 131 DSTs. See Drill-stem tests succession, 119-120 Carbon EAFs. See Empirical adjustment factors aromaticity, 249 Eagleford Formation, 14 isotope data, 124 shales, EOM data, 19 Carbonates, shelfal, 92. See also Mardin Group Ekofisk field (North Sea), 69-70

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El Paistle field (Texas), 259 Greater Green River Basin, 284-285 Empirical adjustment factors (EAFs), 1-2, 10-11 Gulf of Mexico, 49 EOM. See Extractable organic matter Tertiary shales, 259 Equilibrium gas/ oil contact, 60 Gullfaks field (North Sea), 69-70 Eromanga Basin (Australia), 143-144, 160-161 Gussow's principle, 59 capillary leakage, 144 reservoirs, seals, and petroleum occurrence, HCHs. See Hydrocarbons, column heights 145-148 Helium porosity, 87 Exploration High-permeability sands (HPS), 161 programs, 76-77 High-pressure mercury I air injection curves (HPMIC), rationale, 82 1-2, 5 risk, new paradigm, 295 cutting curve, 11 strategy, new paradigm, 296 typical curves, 6-10 Extractable organic matter (EOM), 14, 15, 18, 19 High-pressure mercury injection porosimetry (MIP), 31 asphaltene fraction, 117 Hoadley gas field (Canada), 289 concentration, 128 Horner Method, 303-304 Snorre reservoir, 120 HPMIC. See High-pressure mercury I air injection variations in records, 128-131 curves HPS. See High-permeability sands Facies HRDZ. See Hydrocarbons, -related diagenetic zone seal analysis, 24 Hutton Sandstone, 159 shelf carbonate, 24 edge water drive, 152 Faults leakage, 153 blocks, 49 reservoir, 155 leaks, 135, 139 reservoir seal couplet, 148-150 seal capacity, 54 Hydrocarbon(s) slip, 264 accumulation, 199-200, 217-218 thickness, 110 column heights (HCHs), 1-11 zones, 54, 104-107, 113 composition in Cretaceous-Tertiary succession, characterization, 104-107, 113 Snorre field, 121-128 Filled-to-spill, 65-66 content vs. seal capacity, 24-25 Fingerprinting, 25-27 entrapment, 2 Fluid fraction, 117 content, 304-305 indigenous and nonindigenous, 22-24 flow, 103-104, 108, 113 leakage, 116, 225, 302 Fluid-pressure compartments migration, 113, 213 development, 224-225 molecular fingerprinting, 25-27 reservoir-scale, 230-233 oil-like, 117 stratigraphic controls, 223-239 -related diagenetic zone (HRDZ), 158 Foreland zones, SE Turkey, 169-170 reserves, 280 Fracturing, 293-294 seal type classification, 250 Gas Illite, 38 accumulations, searching for, 284 Intermediate mercury-air capillary entry pressure, 111 buoyancy gradient, 43 Interval velocity, 272-273, 276 chimney, seismic, 116 chromatography, 15, 118-119 Jackson oil field (Queensland), 152-154 compartments, 199-200 Jena oil field (Australia), 161-162 exploration, new paradigm, 283-296 Joffre oil field (Alberta), 309 flushing, 74 Joints, leakage through, 264-266 migration, 111 sands, tight, 283-296 Kaolinite, 38 Geochemistry, organic, 247-250 Karabogaz Formation, 174 Gidgealpa Karakus oil fields (Turkey), 169-170 oil and gas field (Australia), 154-159 Kerogens, 18 seal at, 156 sorption capacity, 20 Gradients Kyrre Formation, 120 buoyancy, 43 formation pressure, 52 Laramide basins (Wyoming), 199-200 fracture, 219 anomalous pressures, 204-214 geothermal, 192-193 changes, 252 overburden pressure, 52-54 Cretaceous shales in, 243-252

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Rocky Mountain, 283-296 Muddy Sandstone Lazy B field reservoir (Wyoming), 233 Cretaceous complexity, 239 Leakage, 116, 131-132 field characteristics, 232 along faults, 262-264 stratigraphic compartmentalization, 230-233 through joints, 264-266 Mudshale, 37 through pore throats, 261-262 Mudstone, 35-37, 45 Lewis Shale, 285 Multiple ion mode (MID), 119 Limestone Creek field (Australia), 161-162 Murta Formation, 155, 160-161 Limestones, 97 Murteree Ridge (Australia), 160-162 stringers, 69 water drive problem, 144 Lineaments, regional, 293-294 Murteree Ridge fields (Australia), 143-144 Lithofacies, 87 potential sealing, 90-92 Namur Sandstone, 155, 158-161 reservoir, 88-90 NCTL. See Normal compaction trend line seal, 98 Neogene uplift, 80 Little Lost Soldier field (Wyoming), 70 Networks, pore/kerogen, 25 Logs, sonic. See Sonic logs NMO. See Normal move-out NMR. See Nuclear magnetic resonance Magic angle spinning (MAS), 248 Normal compaction trend line (NCTL), 54 Mahakam Delta (Indonesia), 72 Normal move-out (NM0), 271 Mardin Group carbonates, 169-170 North Sea age, 170 faults, 103-113 depositional environment, 171 northern, 81, 104-105 diagenesis, 176-177 southern, 105-107 properties, 195-196 North Valiant field (North Sea), 106 reservoir characteristics, 178-189 Norway, 77-79 reservoir quality, 171,176-177, 189-195 Nuclear magnetic resonance (NMR), 208 MAS. See Magic angle spinning Matrix volume reduction, 45 Oil Maturation, thermal, 206 column, 130 Measurements, direct, 206-211 gravity, API, 193 Mercury migration, 111, 162-163 displacement pressure, 38 saturation, 14, 20-22 injection capillary pressure (MICP), 2, 11, 13, 15, 23, "subtle," 305-306 85, 148 Oseberg field (North Sea), 68-69 injection porosimetry (MIP), 37-38, 44, 445 Overburden pressure gradient, 52-54 intermediate capillary entry pressure, 111 Overpressuring, 218-219, 223-224 saturation, 5 basinwide zone, 227-230 Mesaverde Group, 284, 285, 290 dominant mechanism, 211-213 MICP. See Mercury, injection capillary pressure hydrologic, 219 MID. See Multiple ion mode timing, 214 Migration Overthrust frontal zone, SE Turkey, 169-170 chains, 75-77 hydrocarbon, 62 Paradigm -rate calculation, 1 08-111 application, 295 -related diagenetic zones (MRDZs), 158-162 new exploration, 295-296 routes at Minnelusa, 236-239 Patchawarra Formation, 154 Minerals, nonclay, 36 Permeability, 39-41, 212 Minnelusa Formation capillary pressure measurements and, 107-108 complexity, 239 reliability of measurements, 302-304 depositional setting, 235-236 S curve and, 307-310 lithologies, 235 Pore pressure migration routes, 236-239 characterization, 255 regional stratigraphy, 235-236 zone four limits, 257-259 reservoirs, 238 zones, South Texas fields, 256-257 source rocks, 236-239 Pore(s) stratigraphic compartments, 236-239 saturations, 13 MIP. See Mercury, high-pressure injection porosimetry system, water-wet, 19 Modeling, 208-211 throats, 45, 261-262 Monte Christo field (Texas), 258, 259 volume, 5 Moorari oil and gas field (Australia), 159-160 Porosity, 20, 35, 39, 51, 95, 109 MRDZs. See Migration, -related diagenetic zones helium, 87

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homogeneous distribution, 177 Triassic, 304 sandstone, 292 Sandstones, 51, 89-90 Powder River Basin (Wyoming), 223-239 Sarita-Sarita East field (Texas), 257-258 compartmentalization, 204 Saturation, nonwetting phase, 6, 10 Cretaceous section,227-233 Sayindere Formation, 174 fluid properties, 205 Scanning electron microscope (SEM), 10, 107 Permo-Pennsylvanian section, 233-239 Seal(ing)(s) Pressure analysis, 24 boundaries, 283-289 breached compartment, 216-217 causes, 215 capacity, 24-25, 31-32, 54, 44, 85, 93-95, 164-165 compartment. See Pressure compartment capillary capacity, 224-225, 250-252 vs. depth profiles, 256 classification, 250 differentials, 49 closure, 64, 67, 78 gradients, 51-54 Cretaceous shale capacity, 213-214 regimes, 200-204, 214-217 defined, 116 Pressure compartment(alization)(s), 212, 219 evaluation, 22-24, 162 boundary detection, 275-278 facies permeability, 299-310 overpressuring and, 218-219 faults, 50 regional-scale, 269-280 geometry, 32, 92-95, 97 seismic characteristics, 269-280 integrity, 32, 97-98 Pressure-volume-temperature (PVT), 138 lithofacies and, 90-92, 98 Pristane, 27 potential (SP), 22-23, 85-86, 96, 100 Production index, 206-208 quality variability, 80 PVT. See Pressure-volume-temperature vs. reservoir, 306-307 shale capillary, 32 Quartz, 45 strength, 57-58, 60, 63-67, 78, 81 adsorption capacities, 20 study, 24-27 content, 41 types, 2-3 grains, 107 Section analysis, displaced (DSA), 135 shielding, 42 Sediment change, 143-144 Rannach Formation, 105 craton-derived (CD), 143-144 Red Fish Bay field (Texas), 257, 259 Seismic character variations, 270-273 Reflectance, vitrinite, 208, 247 SEM. See Scanning electron microscope Reflection data, seismic, 270 Sequences, fluvial/lacustrine, 144 Repeat formation tests (RFTs), 138, 161, 201 Shales, 88 Reservoirs anomalously pressured Cretaceous, 243-252 Amos Draw field, 233 classification, 33 Birkhead Formation, 148-150, 155 clay rich, 42 Eromanga Basin, 145-148 composition, 34 Hutton Sandstone, 155 Cretaceous and sonic velocities, 244-247 hydrocarbon composition, 120-121 delta-front, 91 Lazy B field, 233 delta-plain, 90, 98 lithofacies, 88-90 displacement pressure, 214 Mardin Group, 178-195 kerogenous, 18 Minnelusa Formation, 238 nonorganic, 31, 41, 43 quality, 106, 189-195 nonsmectite, 44 vs. seal, 306-307 organic, 31, 43 Snorre field, 120 porosities, 52 RFTs. See Repeat formation tests prodelta, 92, 99 Rift basin fields, 136-139 smectite, 33 RMS. See Root mean squared Upper Cretaceous, 206 Rock-Eval Shelf carbonates, 95, 99 data, 14 Shetland Group, 132 parameters, 21-22 claystones of, 121-128 Root mean squared (RMS), 271 Siltstones, 88, 97, 99 channel abandonment, 90 Snorre field (North Sea), 69-70, 115-132, 120 Salinity, 40 Escarpment/Inner Snorre Fault, 128 Sand Sonic logs, 200-201 high-permeability (HPS), 161 Sonic velocities, 243-250 tight gas, 283-296 South Texas Gulf Coast basin, 266

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South Texas oil and gas fields failure of, 64 leakoff pressure, 260-261 fills, 135-141 overpressured, 255-266 fractured, 66 SP. See Seal, potential gas-prone, 59 Spillpoints, 63, 65-66 oil-prone, 59 cryptic, 58 two-phase prone, 59 structural, 96 updip, 77 Spots uplift and, 72-75, 82 dim. See Dim spots Traveltime, two-way (TWTT), 272 sweet. See Sweet spots Triassic sand, 304 Springen Ranch lineament, 233 Tricyclic diterpanes, 128 Stacked section, 273, 275 Troll East field (North Sea), 68 Stacking velocity, 271-272, 276 Turner Valley field (Alberta), 73 Standard Draw-Echo Springs field(Wyoming), 290, Two-way traveltime (TWTT), 272 293-294 TWTT. See Traveltime, two-way Steady-state, 62 Strata, Cretaceous/Tertiary, 130 Uplift, 57, 80 Strike length, 110 trap classes and, 72-75 Succession, Cretaceous-Tertiary, 121-128, Upper Miocene allochthonous unit, 170 Sweet spots, 289-295 VAD. See Volcanic-arc-derived sediment TAF. See Talang Akar Formation Variability, 21 Talang Akar Formation, 14, 86 Velocity BZZ field, 86-87 analysis, 278 depositional setting, 87-92 interval, 272-273, 276 seal potential, 100 semblance coherency plots, 275 seal study, 24-27 sonic. See Sonic velocities stratigraphy, 87-92 variations, 271-273 TDS. See Total dissolved solids Verification, statistical, 77-79 Tectonics, 164 Viking/Kinsella gas field (Alberta), 303, 309 TEGC. See Thermal extract gas chromatography Vitrinite reflectance, 208, 247 Temperatures, bottom-hole (BHT), 192-193 Volcanic-arc-derived (V AD) sediment, 143-144 Thermal extract gas chromatography (TEGC), 25-27 Tight gas sands, 283-296 Washakie Basin, 284 Tirrawarra Sandstone Formation, 154 overpressuring in, 286-287 TOC. See Total organic carbon pressure boundary, 285-289 Toolachee formation, 154 Waste strata, 66 Total dissolved solids (TDS), 205 Water permeability, 40 Total organic carbon (TOC), 14, 34 Wells Trap(s) information, integration of, 273-275 classes, 59-63, 67-70 logs, 51-54 closure, 57 Wertz field (Wyoming), 70 commercial, 64

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