Petrophysical analysis case studies

This article presents brief summaries of detailed petrophysical evaluations of several fields that have been described in the SPE and Soc. of Professional Well Log Analysts (SPWLA) technical literature. These case studies cover some of the complications that occur when making net-pay, porosity, and water saturation (S_w) calculations.

Prudhoe Bay field

Prudhoe Bay is the largest oil and gas field in North America with more than 20 billion bbl of original oil in place (OOIP) and an overlying 30 Tscf gas cap. In the early 1980s, the unit operating agreement required that a final equity determination be undertaken. In the course of this determination, an extensive field coring program was conducted, which resulted in more than 25 oil-based mud (OBM) cores being cut in all areas of the field and some conventional water-based mud (WBM) and bland-mud cores in other wells. Also, several major laboratory programs were run to address various technical issues regarding the correct approach to calculate porosity and water saturation. The background geologic understanding of the major reservoir, the Ivishak or Sadlerochit, and various technical studies have been presented in a number of technical papers.

Geologically, the Sadlerochit reservoir is a combination structural/stratigraphic trap consisting of a 500-ft reservoir interval covering an area of 15×35 square miles at a depth of 8,000 to 9,000 ft. This reservoir is mainly very high quality deltaic Permo-Triassic sandstones deposited in a braided stream environment, ranging from fine-grained to conglomeratic, with some limited intervals of shales found in various areas of the reservoir. The reservoir has been divided vertically into eight zones on the basis of differences in rock types (see Fig. 1). The grains are primarily:

• Quartz
• Quartzite
• Chert

Over geologic time, there have been significant leaching and cementation. The chert grains have been leached to varying degrees, resulting in a significant intragranular component (10 to 60%) of the pore system. There are considerable amounts of siderite and pyrite cementation, together with quartz overgrowth and kaolinite cementation.

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  Fig. 1 – Reservoir zonation of the Sadlerochit reservoir, Prudhoe Bay field, Alaska, US

The structural and hydrocarbon-filling histories of Prudhoe Bay are very complicated; this is clearly evident from a visual examination of the cores, the routine-core-analysis fluid-saturation data, and an interpretation of the seismic data. Oil initially filled this trap 40 million years ago. Since that time, because of differential burial, there has been a change in the configuration of the trap. Where there was previously a 2,000-ft closure, currently there is less than 1,000-ft maximum closure. The reservoir "tilting" resulted in a relict-oil zone systematically varying in thickness, which underlies the current oil column particularly to the southeast. At its base, the relict-oil zone had a flat OWC at the end of the original oil filling. Later, gas migrated into the trap creating a large gas cap over the main area of the field, but also smaller ones in the west-end area of the field. At discovery, a 40- to 60-ft heavy-oil-tar (HOT) layer was found above the current OWC with the oil gravity decreasing upwards from there. No relict-oil interval and essentially no HOT interval are found in the western part of the reservoir (see Figs. 2 and 3).

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  Fig. 2 – Areal structure map showing gas-cap and oil-column distribution in the Sadlerochit reservoir, Prudhoe Bay field, Alaska, US

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  Fig. 3 – Cross section showing hydrocarbon distribution at discovery in Sadlerochit reservoir Prudhoe Bay field, Alaska, US

The net pay was based on defining the shale and siltstone intervals as nonpay. Except for the inclusion of a small number of highly cemented sandstone intervals, this is effectively equivalent to a permeability cutoff of 0.6 md on the basis of routine-core-analysis permeability data, unadjusted to reservoir conditions. The net pay was determined from geologists’ core descriptions. A GR-log model was used to define the pay/nonpay intervals within the Sadlerochit reservoir interval using the more than 450 logged wells’ normalized GR logs. Radioactive sandstone intervals had previously been edited out of the core-log database. This GR-log model had to account for both thick and thin shale intervals, which it did by using three parameters—GR-sand, GR-thin, and GR-thick. The reservoir area was subdivided to account for areal variations when calibrating the GR-log model to the geologists’ core picks of shale and siltstone intervals.

Porosity in the Sadlerochit interval was based on use of routine-core-analysis porosity data and sonic logs. The density log was not used because of the heavy-mineral effects discussed previously. The porosity data were not adjusted for overburden stress at reservoir conditions because it was found that the highly asphaltic crude oil had not been thoroughly cleaned from the core plugs during the routine laboratory procedures. Because there were generally both full-diameter Boyles-law and sum-of-fluids porosity measurements on the pebbly-sandstone and conglomeratic intervals (and both core-plug Boyles-law and sum-of-fluids porosity measurements for the other intervals), a hierarchy of these data was used when preparing the core standard for use with the sonic logs. The sonic log was calibrated linearly to the core porosity data. The calculations were performed individually for each of the eight zones and the different fluid intervals, for example:

• Gas cap
• Oil column
• Aquifer

Finally, the reservoirwide porosity solution for each of these zone/fluid combinations was arealized to account for remaining systematic differences.

The OBM cores indicated that there is a wide range of S_w values, from less than 5% PV in the updip oil column and its overlying gas cap to as high as 50 to 70% PV in the west-end and southwestern portions of the Sadlerochit reservoir. Conventional log-analysis and capillary pressure methods suggested a much narrower range of S w values. For these reasons, major studies were undertaken to identify the reasons for these differences and to determine if the OBM-core S_w data were valid. The primary conclusions were as follows:

• The OBM-core S_w data are valid. This was confirmed by detailed observations and measurements at the wellsite at the time of coring some of the wells and at the commercial laboratory where the routine-core-analysis measurements were made.
• The centrifuge P_c data were found to agree with the OBM-core S_w data after the following effects were accounted for: the laboratory P_c/S_w measurements were run sufficiently long to reach equilibrium, it was recognized that various portions of the Sadlerochit reservoir were on different drainage and imbibition cycles on the basis of either the ancient or the current OWC, and the vertical variation of oil densities and the effect of the HOT interval were accounted for.
• The S_w calculations from the special-core analysis (SCAL) measurements of rock electrical properties agreed with the OBM-core S_w values after the following effects were included: native-state rock electrical properties were measured at the wellsite and restored-state rock electrical properties were measured in the same S_w range as found from the OBM cores; and the variations in the R_w in the oil column and gas cap were included in these S_w calculations. The n parameter was found to vary significantly as a function of S_w because of the complicated intergranular/intragranular (inhomogeneous) nature of the Sadlerochit pore system.
• An independent in-situ measurement of S_w using the single-well chemical-tracer test produced results consistent with the OBM-core S_w at two updip well locations.

The S_w methodology for the Sadlerochit reservoir was a combined use of the OBM-core S_w data with R_t values from the deconvolved deep induction logs. Because of the low clay-mineral content of the Sadlerochit reservoir, an Archie S_w equation was used with n values derived for each zone at the OBM-cored wells and then trended over the reservoir. This results in foot-by-foot S_w calculations for the whole hydrocarbon column in the more than 450 logged wells. This very large database of S_w values was converted into a relationship involving porosity and H_owc and subdivided to account for systematic variations from one area to the next, before making the OOIP and original gas in place (OGIP) calculations.

In summary, the Prudhoe Bay field shows that accurate petrophysical calculations can be complex, particularly in large reservoirs. If a typical approach had been used to make the various petrophysical calculations, the OOIP, OGIP, and the distribution of the hydrocarbons would have been significantly in error. Only through detailed core review by the geologists and by working through a number of complicated laboratory studies was closure reached. The same S_w values were then calculated using the various independent S_w methods.

West Howard-Glasscock unit oil field

This west Texas San Andres oil reservoir is an example of the petrophysical evaluation of a carbonate reservoir. It is one of many San Andres oil reservoirs found in the Permian Basin of west Texas, US, and is presented to show that good-quality core/log petrophysical calculations can be undertaken even when a reservoir covers only a few square miles.

This study was performed in the 1970s after this unit was formed, and the waterflood of the San Andres reservoir was expanded. A total of 40 new wells was drilled with WBM and logged. Ten wells were extensively cored. The new wells were primarily for water injection and added to the existing 80 wells. This coring program was instituted because of the reservoir’s complex and heterogeneous lithology and to aid:

• Log interpretation
• Geological mapping
• Injection-well planning

The routine-core-analysis measurements were primarily performed on whole core samples. Fig. 4 displays, through a permeability vs. porosity plot, the very heterogeneous nature of this reservoir. A number of plug samples (1.5 in. in diameter and 2 in. long) were cut for SCAL studies. Figs. 5 and 6 show a comparison of the SCAL samples’ permeability and porosity data with those from the adjacent whole-core data and show how heterogeneous this reservoir is. Previously published San Andres P_c/S_w correlations were used to calculate the irreducible S w in the log calculations.

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  Fig. 4 – Core-permeability/core-porosity data for Zone D, West Howard-Glasscock Unit, west Texas, US The line fit is manually estimated.

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  Fig. 5 – Comparison of whole-core permeability with core-plug permeability (West Howard-Glasscock unit, west Texas, US).

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  Fig. 6 – Comparison of whole-core porosity with core-plug porosity (West Howard-Glasscock unit, west Texas, US).

The reported SCAL measurements focused on lithology, grain-density, and electrical-property measurements. The grain densities of the vast majority of the tested samples (82%) were in the 2.84- to 2.86-g/cm³ range. The average m from tests on 32 core plugs was 2.1 (assuming a = 1.0). The average for n was 2.2; however, the data were quite scattered (see Fig. 7).

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  Fig. 7 – Laboratory-measured formation resistivity index (I_R) vs. brine saturation for core plugs from West Howard-Glasscock unit, west Texas, US

Log computation software was used to calculate lithology and porosity. The volume of shale present was computed from the sonic and density logs because the GR log was not a good shale indicator because of the presence of many radioactive zones containing little or no shale. Variables calculated were primary porosity, secondary-porosity index, dolomite, sand, anhydrite, and shale. Fig. 8 presents a comparison of the computed and the core porosity values. The permeability, S_w, and S_wi were calculated from the logs on the basis of relationships derived from core data.

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  Fig. 8 – Agreement of core-analysis and Bitri-computed porosity for West Howard-Glasscock unit, west Texas, US “Bitri” refers to the log-response simultaneous-equations solution used to obtain porosity and rock-component volumes.

Oil fields-offshore Peninsular Malaysia

Several technical papers have been written about the combined use of core and log data to increase the reliability of the petrophysical calculations for the various oil reservoirs found in this basin. These papers particularly address how the calculations of fluid saturations were improved, and the uncertainty reduced, by a variety of coring and core-analysis studies. The bottom line to the technical work regarding the Dulang oil field was that the best estimate of OOIP was increased by approximately 30%, which led to management being more confident regarding further development.

The oil fields of the Malay basin consist of stacked sequences of laminated sands and shales. Dispersed clay minerals are present in the sands in the form of kaolinite, illite, and mixed-layer clays. The connate waters are generally of low salinity and impacted by the presence of meteoric (surface) waters. The resistivity-log readings in the sand intervals are suppressed because of the thin-bed effects.

For the reasons described in the previous paragraph, OBM- and bland-mud-coring programs were undertaken in the stacked oil reservoirs of several of these fields. These coring programs’ design and execution paid great attention to all of the details before, during, and after the coring operations. The cores were generally cut at high rates of penetration (60 to 90 ft/hr) and with low overbalance pressure (maximum of 200 psi). Because of the friable and unconsolidated nature of some of the sands, full-diameter cores were frozen in dry ice before plug cutting with liquid nitrogen. Special testing, including the use of mud-system tracers, was conducted to determine that OBM filtrate had not impacted the connate-water saturations. Because some unpublished studies suggested that some of the connate water might be displaced as far as 100 to 150 ft above the OWC, core-layering tests were run to determine the depth and concentration of mud tracers within the cross section of the core. The layering tests found that OBM-filtrate invasion was insignificant.

The routine-core-analysis measurements of OBM cores included Dean-Stark S_w determinations and water-salinity studies. Sponge cores were analyzed for residual-oil saturations. SCAL core samples were taken for rock electrical-property measurements. Fig. 9 presents an example plot showing a comparison of the core results and the results calculated from the logs.

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  Fig. 9 – Plots of core- and log-calculated hydrocarbon pore volume, porosities, and S_w vs. depth for a Malaysian shaly-sandstone reservoir-Core #3.

The results from the analysis of the Dulang field’s various studies were as follows:

• The Dulang reservoirs’ connate S_w was found, from OBM cores, to range from 20.1 to 43.1% PV with an average of 33.6% PV, compared with the previous range of 19 to 61% PV with an average of 39% PV. Also, the S_w varies from reservoir to reservoir, as controlled by the reservoir quality and depositional environments.
• Measurements of water salinity and R_w indicated that R_w varied with reservoir depth and was not constant as previously assumed (see Table 1).
• Rock electrical-property measurements indicated that m and n have values of 1.77 and 1.64, respectively (assuming a = 1.0). n was significantly lower than the previously used value of 1.89 (see Table 1).
• Core data were used to calibrate the dual-water (DW) model.
• Residual-oil saturation data indicated that S_orw ranged from 25.8 to 29% pore volume (PV) with an average of 27.5% PV. Recovery factors ranged from 37.8 to 49.4% for the various reservoirs.

The effect of these changes in the petrophysical calculations for the various reservoirs was that S_w had been previously overestimated. The impact of the revised calculations and new core data for the Dulang field’s OOIP was that it increased from 550 to 685 million STB.

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  Table 1

Block A-18, gas/condensate field, Malaysia-Thailand joint development area

This example used core P_c and log data to increase the reliability of the petrophysical calculations for gas/condensate reservoirs found offshore near the Thailand-Malaysia border. It addresses how the S_w calculations were improved by the integrated use of resistivity logs in a shaly-sand model and P_c data measured on core plugs. The calibration method led to the resistivity model reproducing the S w given by the core-measured P_c data. The end result of the work was a well-supported increase in OGIP estimates for the A-18 gas field, leading to a greater confidence in the development viability. The best estimate of gas reserves was increased by more than 20%.

In the first part of the calibration method, the shaly-sand sequence is classified into several facies according to the clay distribution. Initially, 10 facies are identified in the cores, but they are reduced to four petrophysical facies consisting of:

• Clean sands
• Sands with discontinuous clay
• Bioturbated and heterolithics
• Poor reservoir mainly consisting:
  • Mudstones
  • Coals

The electrical continuity of the shale components increases with each facies. Where core is not available, the facies type is estimated, preferably from resistivity imaging logs. P_c data were acquired on 1.5-in.-diameter plugs using the centrifuge method and spanned the full range of reservoir parameters. A multiple-linear-regression prediction of S_w from P_c, porosity, and permeability was used to estimate S_w at every routine-core-plug depth.

In the second part of the calibration, the P_c-predicted S_w values were correlated with the Waxman-Smits shaly-sand model and the deep-resistivity log values at each foot of the core. The Waxman-Smits model and the resistivity log were forced to match the P_c-based S_w by back-calculation of the n* value at each foot in a way similar to that described for OBM cores in the main S_w page (water saturation determination). A mean back-calculated n* is then determined for each of the four facies. Table 2 gives the n* mean values, along with the usual SCAL electrical-properties n* values acquired by measuring core-plug resistivities in the laboratory. The P_c-calibrated n* values are significantly lower than the SCAL electric-property n* values, leading to significant increases in effective hydrocarbon column, especially in the bioturbated and heterolithic sands.

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  Table 2

Total porosity at every logged foot was calculated from the density-log force fitting the line-fit through the core grain density. Fig. 10 shows mainly raw data with the S_w results at the right side.

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  Fig. 10 – Water saturation S_wws calibrated to capillary pressure P_c core data and S_wsca calibrated to standard core-electrical-properties n*. The P_c-based solution provides lower S_w results in this offshore gas field in the Malaysia-Thailand Joint Development Area. From left to right: Track 1 = GR log and caliper showing washouts; Track 2 = high resolution density log and other porosity logs; Track 3 = laterolog deep resistivity, shallow resistivity, and microspherically focused log; Track 5 = facies identifier and mud-gas log; and Track 6 = S_wws, the P_c-calibrated core/log n*-derived S_w and S_wsca, and the standard rock-electrical-properties n*-derived S_w.

Whitney Canyon-Carter Creek gas field

This Wyoming, US, gas field produces from a 1,000-ft-thick complex carbonate with a wide range of minerals including dolomite, anhydrite, limestone, and quartz. The study hoped to examine significant differences in well performance and to provide recommendations to increase recovery.

The main reservoir is in dolomitic rocks where there is a full continuum from slightly to fully dolomitized limestones. There is little or no relationship between permeability and porosity. Four rock types were identified by high-pressure mercury injection (HPMI) and, because this reservoir has very high P_c (deriving from the 1,000-ft-thick gas column), even the poorest dolomitic rock has some gas saturation in the small pores. Table 3 gives a summary of the petrophysical properties of the four rock types.

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  Table 3

Porosity and mineralogy were evaluated with a probabilistic simultaneous-equation method. Gas corrections were required and had a significant effect on the results because, while the density-log reading is shallow, the neutron log is much deeper. Boron, a neutron absorber, is present in the dolomites and required a correction. S_w was calibrated to Dean-Stark initial S_w measurements and to the HPMI P_c measurements (Fig. 11 because the laboratory Archie n measurements (1.1 to 1.5) were unreliable in the "tight" rocks. Force-fitted Archie exponents of m = 2.18 and n = 2.0 were used in the evaluations, and provided similar results to the OBM core S_w and HPMI P_c data.

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  Fig. 11 – High pressure mercury injection (HPMI) plots for Whitney Canyon-Carter Creek field, Wyoming, US for Rock Types 1, 2, and 3 (See Table 2): (a) mercury intrusion as pore-throat radius changes and (b) wetting-phase saturation as height above free-water level (H_GWC) changes (after Gunter et al.). Each rock type is represented by 4 or 5 core samples. Plots for Rock Type 4 are not included because those are the poorest rocks with nano-sized pore throats.

Gas saturations up to 75% PV were calculated for the poorest rock type and represented a significant prize for the production team. Positive steps were taken to ensure that this gas was accessed by production wells. The study determined that, as well as the usual acid stimulation of the higher-quality rock, the poorer rocks should also be separately stimulated with acid. Acid diversion to lower-permeability zones was used in new infill wells.

Nomenclature

m*	=	Waxman-Smits-Thomas cementation exponent
n*	=	Waxman-Smits-Thomas saturation exponent
a*	=	Waxman-Smits cementation constant
Qv	=	cation-exchange capacity of total PV, meq/mL
Howc	=	height above the oil/water contact, L, ft [m]
Pc	=	capillary pressure, m/Lt2, psi
Rt	=	true resistivity of uninvaded, deep formation, ohm•m
Sw	=	water saturation, %PV

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See also

Petrophysics

Petrophysical data sources

PEH:Petrophysical_Applications

PEH:Petrophysics