33

IPA05-E-145

PROCEEDINGS, INDONESIAN PETROLEUM ASSOCIATION Thirtieth Annual Convention & Exhibition, August 2005

INTEGRATED PETROPHYSICAL FORMATION EVALUATION USING CAPTURE

SPECTROSCOPY AND NMR ON AN EXPLORATION WELL, SOUTH SUMATRA

ZhanGuo Shi* Mario Petricola* PingZai Wang**

ABSTRACT This paper presents an integrated petrophysical formation evolution on two complicated geology settings penetrated by an exploration well in South Sumatra region. The rich information from the capture spectroscopy and nuclear magnetic resonance provides tremendous applications on fluid typing on the low resistivity contrast sandstones in a fresh formation water environment; and the lithology identification plus other reservoir properties characterization on an unconventional reservoir. The interpretation guided the selection of test candidates and has been confirmed by the test results. The first formation is a clastic sequence where fluid typing was the main challenge. On conventional logs most of the sands have similar petrophysical characters, in terms of the resistivity reading, lack of Density-Neutron cross over, etc. In addition, a dubious clay volume derived from gamma ray and fresh formation water made the interpretation even more challenging. In view of these difficulties, The Company decided to acquire capture spectroscopy and NMR logs in order to reach a solid conclusion for the first exploration well in this structure. All hydrocarbon-bearing zones were clearly identified. The sedimentary sequence for the main gas-bearing sand was clearly revealed by the spectroscopy-NMR combination; for another zone, the spectroscopy log showed a much lower clay volume compared to the traditional GR estimation, and the Density-NMR combination revealed this zone to be gas bearing, even though there was no Density-Neutron cross-over. A gas cap was identified on the * Schlumberger ** PetroChina International

top of massive water-bearing sand, raising expectation that more gas can be found higher in the structure for the same sand. At the bottom of the same well, a very radioactive massive formation was discovered, the natural gamma ray spectrometry showed that both thorium and potassium readings are very high; neutron and density logs cannot provide conclusive lithology and porosity as well. Capture spectroscopy identified one clean sand at the top of the formation. The permeability from NMR is also high. Very long T2 relaxation times are suggesting that there is big potential of existing very light oil. The detailed mineralogical information derived from the comprehensive measurements of gamma ray capture spectroscopy and NMR implies that the sedimentary environment for this formation is most probably an alluvial deposition and the source rock is weathered granite. This log-based conclusion helped in calibrating the existing reservoir model. INTRODUCTION With a traditional simple logging program, has any hydrocarbon been left behind in an abandoned exploration or development well? For some wells, the answer is probably yes. We often hear that the target formation is well known either based on the regional geological setting or knowledge from nearby fields. Under this hypothesis, a similar simple evaluation program is normally implemented. This article presents a petrophysical case study on an exploration well in Central Sumatra basin where the new measurements give more information on lithology, pore texture and finally fluid type. It also

34

presents the difference compared to a standard logging program. The gamma ray or gamma ray spectrometry logs have been used as the main measurements for lithology evaluation and the density, neutron or sonic are the traditional tools for porosity evaluation. With the advent of new lithology and porosity measurements, such as gamma ray capture spectroscopy and nuclear magnetic resonance (NMR), the reservoir can be characterized more clearly and easily. These two measurements have been in service for quite some time; their principles and applications have been widely documented in various published papers. The article will review the basic principle of those measurements and focus on describing their applications, explaining how the measurements help on identifying low contrast low resistivity pays, fluid typing and evaluating an unconventional reservoir. By demonstrating the applications, the purpose of this paper is to help oil companies select the fit-for-purpose petrophysical formation evaluation technology and design a tailored logging program to reduce the overall exploration or development cost. With the detailed information for a new reservoir, the success ratio for an exploration project will be maximized and hence potentially shorten the development cycle by reducing the number of appraisal wells. LITHOLOGY CHARACTERIZATION FROM CAPTURE SPECTROSCOPY The Evolution of Lithology Evaluation GR is the basic log used for correlation and for lithology control, in certain conditions the shaliness can be derived from it; besides the gamma ray, the neutron and density combination has also been well used for clay volume and porosity estimation, especially for radioactive shaly sands. Gamma rays are bursts of high-energy electromagnetic waves that are emitted spontaneously by some radioactive elements. Nearly all of gamma radiation encountered in the earth is emitted by radioactive potassium isotope of atomic weight 40 (K40) and by radioactive elements of the uranium and thorium series. The natural Gamma ray log (GR) is a recording of the natural radioactivity of the formation.

There are two main types of gamma ray logs, the standard GR log measures only the total radioactivity, whereas the spectral GR such as the NGS (Natural Gamma Ray Spectrometry) log, measures not only the total radioactivity but also the concentrations of potassium, thorium and uranium producing this radioactivity. Lithological analysis from well logs made a giant leap forward with the development of neutron-induced gamma ray spectroscopy. The technique is based on the prompt emission of characteristic gamma rays when neutrons emitted from a source in the tool are scattered or captured by formation nuclei after they have slowed down to thermal energy level. Spectroscopic detection of these gamma rays allows the identification of the nuclei that emitted them and the quantification of their abundance. The purpose of induced gamma ray spectroscopy logging is to obtain elemental concentrations of the formation, a procedure sometimes refer to as geochemical logging. This is achieved by emitting high-energy neutrons from a source in a tool, which then interact with the borehole mud and the formation. Only one of the interactions is of interest, the capture of thermal neutrons by formation nuclei during which characteristic gamma rays are emitted. The energy spectrum of those gamma rays is recorded, and analyzed and concentrations of some elements in the formation are obtained. The measured spectrum is decomposed into its components using standard spectra (Figure 1-1 and Figure 1-2) for each of the elements. At each depth, the linear combination of those standards is determined through a best-fit procedure, and elemental yields are obtained, the sum of which is one by definition. Elemental concentrations are obtained from the yields by rewriting each element as an oxide and putting their sums to unity in a so-called closure model. Because of the complexity of nuclear interactions and imperfect resolution of commercially feasible detectors, there are a limited number of elements that can be quantified in this manner. The Schlumberger elemental capture spectroscopy sonde (ECS) has a standard americium-beryllium (AmBe) chemical source, which is also used in neutron porosity tools. It emits neutrons at a relatively low energy such that there are practically no inelastic interactions and thus the gamma ray spectrum is

35

dominated by capture reactions. It is recorded by a cooled bismuth germanate (BGO) detector. The good efficiency of this detector allows a high logging speed of up to 1800 ft/hr, and the good spectral resolution provides the element Si, Ca, S, Fe, Ti, and Gd with good repeatability. The comparison of elemental concentrations obtained from the ECS with chemical laboratory analysis on core samples show generally good agreement between log and core data. Mineral Concentrations The principal use of elemental concentration logs is to transform them into quantitative logs of mineralogy. ECS solves for mineral groups instead of minerals. The latest approach is sequential and relies on the relationship of the major measurable elements with the major rock-forming mineral groups found in type reservoirs. Herron and Herron (1996) have proposed to calculate only four minerals, or rather mineral groups from ECS, namely, Clay Quartz-feldspars-mica Carbonates (calcite and dolomite) Evaporates (anhydrite and gypsum) As input they use the major rock forming elements measured from ECS, Si, Ca, Fe and S. Magnesium can be calculated from an estimation of dolomite using other open-hole logs, notably the photoelectric factor. Since no aluminum measurement is available, Al concentration is estimated from a combination of measurable elements which correlate or anti-correlate with Al. From their study on 12 wells, the good correlation with a coefficient of 0.99 between the core-derived aluminum and other minerals (SiO2, CaCO3, MgCO3 and Fe) essence states that whatever is not tied to silicon oxide, carbonates or iron, must correlate with clays and hence with aluminum. It has been observed that average clay contain 20% aluminum. So with accurate aluminum, the weighed dry clay volume can be estimated. With recent acquisition and software development, combining ECS with conventional logs, a suite of complete answers can even be delivered at the well site directly, include lithology, porosity and

saturation, which will help operators make real time decisions on selection of sampling or testing intervals. KEY RESERVOIR PROPERTIES FROM NMR Nuclear magnetic resonance is isotopically selective: at a given magnetic field strength and operating frequency, only a single nuclear species can be detected. Borehole logging tools select 1H, the hydrogen nucleus, or proton, as the species resonated in the formation. The strength of the signal is proportional to the amount of hydrogen in the formation. NMR measures signal amplitude and a signal decay curve. For the modern tools, the signal amplitude is proportional to the formation total porosity, including the clay bound water, the capillary bound water and free fluid. The signal decay curve provides information about the types of fluids and their interactions with the pore space. After the inversion, NMR measurements are normally presented as the transverse relaxation (T2) distribution curve. NMR characterizes the relationship between permeability and porosity, pore size distribution, bound water saturation that is independent on resistivity, formation water salinity, porosity cementation exponent (m) and saturation exponent (n). Above the hydrocarbon-water contact, NMR free fluid saturation is equal to the hydrocarbon saturation and it is probably the most accurate saturation we can get from logs, provided the correct T2 cutoff is used. A NMR T2 distribution is controlled by bulk, surface and diffusion properties, the relaxation for surface and bulk can be expressed as,

AVisc

SwVS

T+= 11

2

(1) Where: T2 = relaxation time, second = surface relaxivity of the grain surface, in

microns/second S/V = pore surface-to-volume ratio, in 1/microns A = coefficient, 1.2 in cp-second Visc = the viscosity of fluid in pore space, in cp The NMR has no borehole effect under normal conditions. When the measurement volume does intersect the borehole, the problem is usually obvious

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on the logs and the measurement is irretrievably ruined. Thus the NMR borehole effect is in essence a go-no go decision instead of a myriad of routine but complicated environmental corrections. Free Fluid Cutoffs NMR T2 cutoff distinguishes the free fluid from the bound water volume in the total porosity. The cutoff heavily depends on the minerals that constitute the formation. The default cutoff for sandstone is 33ms, and for carbonate it is 100ms, which are based on laboratory tests with brine-saturated samples. The principle behind this difference is that, compared to carbonates, sandstones have more paramagnetic material in the matrix. This paramagnetic material increases the surface relaxivity of the grain surface, which in turn delivers a shorter T2 distribution. The cut off varies with rock composition, which is controlled by source rock and depositional environments or facies. For some very clean sandstones, paramagnetic material might be less than normal level, and free fluid cut off will increase accordingly. Permeability Estimation Permeability from NMR is a function of both porosity and pore size, which is a great improvement over traditional permeability estimation technology, which is based on a transform between porosity and permeability only. It should be noted that both producible porosity and permeability are expected to increase with pore throat diameter, whereas NMR responds to pore body diameter. Fortunately, the throat/body ratio is approximately constant for most sandstones. However, it is recommended to have core permeability for coefficients calibration in order to build a robust local permeability model, to minimize the uncertainty on throat/body ratio. NMR permeability estimation is based on an expectation that permeability increases with both porosity and pore size. NMR and brine permeability measurements on core samples have resulted in several empirical correlations. The following permeability models are included in the GeoFrame CMR (Combinable Magnetic Resonance sonde, a Schlumberger NMR tool) processing software:

,)()( 11log,21c

CMRb

SDR TaK = (2) and

2242 )())(10( cCMR

b

BF

FFTIM aK

= (3) Where: KSDR : Permeability transform developed by

Schlumberger Doll Research KTIM : Permeability transform from Timur-Coates ff : CMR free fluid porosity bf : CMR bound fluid porosity CMR : CMR total porosity The default values for the multiplying factors and exponents are: a1=4, a2=1, b1=2, b2=2, c1=4, c2=4. The two transforms are referred to as the SDR and Timur/Coates models, respectively. Gas Identification from Density-Magnetic Resonance (DMR) The total porosity is underestimated by the CMR when gas is present in flushed zone. This is due to the low hydrogen index of gas (the concentration of hydrogen in the gas relative to water), and possible under-polarization. To correct for this, the density measurement, which is also affected by gas, is combined with the CMR, and following simultaneous equations are solved for total porosity (t), and the gas saturation in the invaded zone (Sxg). (After Flaum C, Kleinberg RL and Hurliman MD. 1996). This technique works well because the CMR and the density tool measure similar volumes. ( ) gxgtgntb S += 1 ( ) wwitfwixgt SSS ++ 1 (4) ( ) fwixgtCMR HISS = 1 gasgxgtwwit PHISHIS ++ (5)

= gasTPT

gas eP11 (6)

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Where: PT = polarization time * = density HI* = hydrogen index LOW RESISTIVITY AND LOW CONTRAST PAY IDENTIFICATION The first formation is a clastic sequence, including several shaly sands where fluid typing was the main challenge. Most of the sands had similar petrophysical characters on conventional logs, in terms of the resistivity reading, lack of Density-Neutron cross over, etc. In addition, a dubious clay volume derived from gamma ray and fresh formation water made the interpretation even more challenging (Figure 2). The traditional methods used for fluid typing in this area are resistivity and neutron-density cross over. Based on the neutron-density, resistivity, GR and SP curves, five sands can be easily identified by their lower GR reading, positive SP deflection and separations on shallow and deep resistivity curves. With its obvious neutron-density crossover the lowest sand (A) is clearly gas bearing, the high resistivity reading also supports this interpretation. It is difficult to assess what kind of fluids exist in the upper four sands (B to E), because there is no neutron-density cross over observed, similar resistivity reading, and analysis is also complicated by the deep mud filtrate invasion. The positive SP deflection implies formation water is fresh. The effective porosity and clay volume are unknown. Compared to the lowest sand, GR readings for upper four sands are higher; there is possibly more clay in those sands. In view of these difficulties, the oil company decided to acquire capture spectroscopy and NMR logs in order to reach a solid conclusion for the first exploration well in this structure. Dry weight fractions of the main formation minerals (or groups of minerals) were obtained from spectroscopy processing, including clay minerals, quartz-feldspars-mica, and carbonate. Pyrite and siderite can also be evaluated if required, but were not included here.

NMR provided the total, effective, free, capillary bound and clay bound porosity and a more accurate permeability that takes into account the pore size distribution as expressed in equations 2 and 3 above. A further Density-NMR processing was applied to evaluate the gas volume in the flushed zone. NMR has several advantages compared to neutron tools. Both measurements are sensitive to the hydrogen density, but there are number of differences between the response to reservoirs. NMR tools are sensitive to hydrogen, while other strong neutron scatterers and absorbers, such as chlorine and some rare earth metals, also affect neutron tools; on the other hand, neutron tools respond to all hydrogen, not only hydrogen in water and hydrocarbon but those that form part of clay matrix and those that are associated with crystalline waters of hydration, such as in gypsum, this is the reason why the neutron reading in shales is usually very high. NMR tools are sensitive only to fluid protons. Thus the NMR measurement is a more consistent indicator of the porosity than the neutron measurement; and there is no matrix effect at all on the NMR signal amplitude. (Kleinberg RL and Vinegar HJ., 1996) A coarsening-up sequence in Zone A is clearly revealed by the ECS-CMR combination (Figure 3). In track 1, ECS shows clay volume decreasing upwards and CMR T2 distribution shows the pore size increasing upwards. Large residual gas volume is identified by DMR processing in Zone A, a gas flag is also observed for bottom section of this sand, implying the whole sand is most probably gas bearing. The resistivity reading for this sand ranges from 15 to 40 ohm-m. For Zone B, the resistivity reading is only about 4 ohm-m, a big difference with the gas-bearing sand below. ECS shows much less clay volume than the GR, which can be easily overestimated from its high GR reading. With the advantage of NMR over neutron as mentioned above, the Density-CMR (DMR) processing results clearly reveal that residual gas exists in the invaded zone. Zone B is a gas bearing sand. One solid vertical line representing permeability of 1 mD is displayed in track 5 in Figure3. The DMR gas corrected permeability for zone B is about 10 mD; for the top section, the highest permeability is around 100 mD. Zone A has a much higher quality, the highest permeability is close to 1 Darcy.

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For zone A and zone B, because both sands are above the Gas-Water contact, the free fluid volume from CMR is actually equal to the gas volume. The gas saturation is simply given by the ratio of free fluid volume to effective porosity. The contents of the Figure 3 are listed in below, a composite plot of minerals from ECS, GR, resistivity and CMR processing results. Track 1, Minerals or mineral groups from ECS.

Track 2, Depth track. Track 3, Gamma ray, SP and caliper. Track 4, Shallow and deep investigation lateral

resistivity curves, microresistivity. Track5, Permeability curves. Uncorrected permeability from Timur-

Coates equation (KTIM.CMR); High-resolution permeability from SDR equation (KSDR_HR.CMR); Gas corrected Timur-Coates permeability (KTIM.DMR).

Track 6, CMR total porosity, free fluid volume

(yellow), gas volume identified by DMR processing (Gas from DMR); capillary and clay bound water volume (light yellow and gray); Density log.

Track 7, Eight CMR binary porosity derived from

following cutoffs, 1,3,10,33,100,300,1000 ms.

Track 8, CMR T2 distribution with straight cutoff

of 33 ms. The three massive sandstones on upper section are mainly fresh water bearing sands. However, a gas cap was identified on top of Zone C (Figure 4), which raises the expectation that more gas can be found higher in the structure for the same sand. Lateral resistivity shows there is almost no contrast between the water and gas-bearing sands, hence the saturation from Archie type of equation will be the same for them. In side the massive sands, there are several tight beds with characters of high micro resistivity, low porosity and low permeability on CMR. The good match is a benefit of the pad type CMR design and high resolution permeability processing.

The interpretation guided the candidates selection for testing, Zone A, B and top of zone C have been tested, following are test results (choke size 40/64). Zone A, condensate 345 BCPD and gas 8

MMSCF/D Zone B, condensate 100 BCPD and gas 2.6

MMSCF/D Top of Zone C, gas 1.2 MMSCF/D and water

1298 BWPD EVALUATING THE HOT SAND In the lower section of the same well, a new hot formation, with a character of very high radioactivity, is discovered. The total GR reading for the formation is roughly 400 GAPI; this is not only due to uranium accumulation, the thorium and potassium from NGS measurements are also very high (track 3, Figure 5). Displayed in a sandstone scale, the neutron porosity is much higher than density porosity (far right track, Figure 5). One top of this massive radioactive formation, the array lateral logs identify that there is a potential permeable zone, as the large separations can be observed on array resistivity logs due to the deep saline mud filtrate invasion (track 4). The deep resistivity is flat on upper section of the permeable sand and the borehole with big washout (track 2). Considering the unusual response on logs and good hydrocarbon show on the mud log, and taking account the heavy washout, to verify the measurements the GR, NGS and Resistivity were repeated for the whole high GR interval; the good repeatability confirmed that an unconventional reservoir had just been discovered. Various cross plots can be used for describing the petrophysical characters of this unconventional reservoir. The Neutron-Density cross plot and the Thorium-Potassium cross plot are presented in Figure 6. The Z-axis is the total gamma ray. The dark green clusters represents shales, which are located above the hot formation, and the red and blue points are for the sand. On the N-D cross plot, the red points are far below the overlay of the line of clean sandstone, based on which a high clay content tends to be computed. On the NGS cross plot, the sands show that the concentration of thorium and potassium

39

for the sands are several times higher than the reading for clays above. With a quick evaluation on all conventional logs, it was realized that several reservoir properties were difficult to estimate, including lithology, particularly clay volume, the effective porosity due to the unknown matrix on neutron-density and finally the fluid type. There was suspicion that the high NGS reading was not from clay minerals only. The oil company decided to run the ECS and CMR-Plus (an enhanced CMR tool) to get additional properties for the new reservoir. Even though the hole was far out of gauge, thanks to its pad-type design, the CMR-Plus gave excellent results over most washout intervals. Based on the clay volume from ECS, which is derived in the way elaborated in the ECS principal section and has nothing to do with the major natural GR sources, i.e. the Thorium, Potassium and Uranium, a clean sand is found on top of the massive formation. The integrated petrophysical formation evaluation results for the whole of this unconventional reservoir are presented in Figure 7. CMR permeability for this top sand is the highest, ranging from 10 mD to 100 mD (Red bar in Figure 7). A very long T2 relaxation is also observed over this sand, which implies a potential of light oil existing in the bigger pore space. Compared to the top sand, the sand just beneath has more capillary and clay bound water, Clay volume from ECS is also high (highlighted with a yellow bar in Figure 7); Considering the long T2 distribution, this section is most probably a light oil bearing low permeability sandstone. Most sands below the tight barrier (labeled with a black bar) have a faster relaxation time and large variations on the pore size, giving an indication of poor sorting, hence poor reservoir quality. The CMR permeability for those sands is generally less than 10 mD. For some intervals in the lower section, the micro resistivity is much higher than deep resistivity reading, indicating that some big resistive features, most probably boulders, were penetrated by the drilling bit, meaning that the rock in this interval is a near source deposition. Detailed mineralogical information has been derived from the comprehensive measurements of the natural

gamma spectrometry, density-neutron, resistivity, capture spectroscopy and NMR. ELAN, which is a simultaneous log analysis software, was used for this transform. The interpretation results are presented in the far right track in Figure 7. The formation is described in terms of volumetric fractions of minerals and fluids. The minerals or mineral group used in the model are Quartz, Orthoclase, a Thorium rich heavy mineral, Pyrite, Illite, Montmorillinite, Kaolinite; the fluids are Water and Oil. It comes out that the major clay minerals in the sand are montmorillinite and kaolinite, illite is rare, orthoclase is about 30%, and the percentage of the thorium rich heavy mineral is generally very low. Oil is accumulated on upper section of the formation. Based on the logging response and formation constitutes from ELAN and respecting the local geology setting, the sedimentary environment for this formation is most probably an alluvial deposition and the source rock is weathered granite; the new unconventional sand can be classified as arkose. The permeable sand on top of the massive formation has been successfully tested, Oil production is 297 BOPD, with gas of 0.21 MMSCF/D, the choke size is 24/64, Oil API Gravity is 41 Degree at 60 DegF, a new reservoir with light oil accumulations, supported by the slow transverse relaxation observed on its CMR T2 distribution. CONCLUSIONS Low resistivity contrast sandstones in a fresh formation water environment and an unconventional reservoir discovery by an exploration well in central Sumatra were successfully evaluated by the combination of capture spectroscopy and NMR. Multi-facies applications of ECS and CMR in this exploration well have been observed, 1. Compared to the standard GR or even spectral

GR log, ECS provides superior and more accurate lithology information for both shaly sands and high radioactivity formation. Knowing the matrix properties, the porosity and saturation can then be better estimated from conventional logs.

2. CMR gives rich information on porosity, pore

texture and fluid type, including: T2 distribution - pore size and fluid viscosity

information

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Free fluid volume - Giving accurate hydrocarbon saturation above the H.C-water contact

Density-CMR processing- Fluid typing and

porosity, permeability correction The traditional technology tends to solve the simple problems; to reveal the mystery of some hidden reservoirs new evaluation techniques are needed. In many cases, the reservoir challenges identified from a real time quick-view of the conventional logs, during or immediately after the logging, may be very helpful in choosing the appropriate measurements for a more sophisticated and meaningful evaluation. ACKNOWLEDGEMENT The authors thank the management of PetroChina

International and Schlumberger for permission to publish this work. REFERENCES Flaum, C., Kleinberg, R.L., and Hurliman, M.D. 1996. Identification of gas with the Combinable Magnetic Resonance tool CMR: SPWLA 37th Annual Logging Symposium, paper M Herron, S.L., and Herron, M.M. 1996. Quantitative lithology: An application for open and cased hole spectroscopy: SPWLA 37th Annual Logging Symposium, Paper E Kleinberg RL and Vinegar HJ., 1996, NMR properties of reservoir fluids: The Log Analyst, v. 37, p. 6.

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0 5 0 100 150 200 250

I n e l a s t i c

H

Cl

Si Fe

G d

Energy

0 5

20

40

60

80

100

120

Silic

0 2 4

Calci

0 1 2

Iron

0 1 2 3

Sulf

0 5

Titani

0 1 3

Gadolin

Elemental Concentrations Lithology

Relative Yields Capture Spectra

n

Elemental Standards

Si Ca

Fe

S

Oxides Closure

Figure 1.1 The diagram of the standard gamma ray inelastic and capture. Figure 1.2 The processing chain of capture spectroscopy. From the raw spectra to elemental concentrations

to the minerals.

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A

D

C

B

E

X

X

X

X

X

X

X

Figure 2, Composite of conventional logs for the shaly sands complex, intermediate logging interval

Figure 2 - Composite of conventional logs for the shaly sands complex, intermediate logging interval.

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A

B

Figure 3, Composite plot of ECS minerals, GR, resistivity and CMR processing results for gas bearing sands. The Density-CMR processing results are presented in track 6, pink shading is the residual gas after mud filtrate flooding. The resistivity for Zone B is only about 4 ohm-m . Test results:

9 Zone A, condensate 345 BCPD and gas 8 MMSCF/D9 Zone B, condensate 100 BCPD and gas 2.6 MMSCF/D

Figure 3 Composite plot of ECS minerals, GR, resistivity and CMR processing results for gas bearing sands.

The Density-CMR processing results are presented in track 6, pink shading is the residual gas after mud filtrate flooding. The resistivity for Zone B is only about 4 ohm-m. Test results: Zone A, condensate 345 BCPD and gas 8 MMSCF/D Zone B, condensate 100 BCPD and gas 2.6 MMSCF/D

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Figure 4, Composite plot of ECS minerals, GR, resistivity and CMR permeability, porosity and T2 distribution for three massive sandstones. From DMR processing results, a low resistivity contrast gas-bearing sand is identified on top of the lowest massive sandstone (Zone C), raising expectation that more gas can be found higher in the structure for the same sand. Test results of the top of Zone C: Gas 1.2 MMSCF/D and water 1298 BWPD

D

C

E

Figure 4 - Composite plot of ECS minerals, GR, resistivity and CMR permeability, porosity and T2

distribution for three massive sandstones. From DMR processing results, a low resistivity contrast gas-bearing sand is identified on top of the lowest massive sandstone (Zone C), raising expectation that more gas can be found higher in the structure for the same sand. Test results of the top of Zone C: Gas 1.2 MMSCF/D and water 1298 BWPD.

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X

X

X

X

X

Figure 5, the response of conventional logs on an unconventional sandstone, which is labeled with the yellow bar at the lower section, the upper section is mainly shales. Track 1, caliper; Track 2, nature gamma ray spectrometry; track 3, high resolution lateral log array; track 4, density, neutron and photoelectrical capture factor (PEF).

Figure 5 - The response of conventional logs on an unconventional sandstone, which is labeled with the yellow

bar at the lower section, the upper section is mainly shales. Track 1, caliper; Track 2, nature gamma ray spectrometry; track 3, high resolution lateral log array; track 4, density, neutron and photoelectrical capture factor (PEF).

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TNPH / RHOZInterval : 4500. : 5150.

3.

2.8

2.6

2.4

2.2

2.

RH

OZ

-0.05 0.06 0.17 0.28 0.39 0.5TNPH

0-100

100-200

200-300

300-400

400-500

0.

500.HSGR

SS 0

10

20

30

40

LS 0

10

20

30

40

DOL 0

10

20

30

40

(SWS) Density Neutron(TNPH) overlay, Rhofluid = 1.0 (CP-1e 1989)

721 points plotted out of 1301Well Depths

4500.F - 5150.F

DiscriminatorsHCAL < 10

HTHO / HFKInte rval : 4500. : 5150.

0.

0.02

0.04

0.06

0.08

0.1

HFK

0. 20. 40. 60. 80. 100.HTHO

0-100

100-200

200-300

300-400

400-500

0.

500.HSGR

77 8 points plotted out of 1 3 0 1We ll Depths

4 5 0 0 .F - 5 1 50 .F

Dis c rim ina torsHCAL < 1 0

Figure 6.1 - Neutron vs. Density cross plot for the unconventional sandstone, the cluster of dark green is for

shale, the red and blue clouds are for hot sand, the Z-Axis is total gamma ray. TNPH: Neutron; RHOZ: Density

Figure 6.2 - Thorium vs. Potassium cross plot, the cluster of dark green is for shale, the red and blue clouds

are for hot sand, the Z-Axis is total gamma ray. HTHO: Thorium; HFK: Potassium.

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A

Heavy washut

Figure 7, Integrated display of reservoir properties from ECS, CMR and the volumetric analysis results for the unconventional sandstone. Test result of the top sand, Zone A: Oil production is 297 BOPD, with gas of 0.21 MMSCF/D, the choke size is 24/64, Oil API Gravity is 41 Degree at 60 DegF. The light oil

is supported by the long and consistent T2 distribution over this sand.

Figure 7 - Integrated display of reservoir properties from ECS, CMR and the volumetric analysis results for

the unconventional sandstone. Test result of the top sand, Zone A: Oil production is 297 BOPD, with gas of 0.21 MMSCF/D, the choke size is 24/64, Oil API Gravity is 41 Degree at 60 DegF. The light oil is supported by the long and consistent T2 distribution over this sand.