Thursday, February 21, 2019

Low Resistivity Pay Zones

Evaluating low-resistivity pay requires interpreters to discard the notion that water saturations above 50% are not economic. Various tools and techniques have been developed to assess these frequently bypassed zones, but there are no shortcuts to arriving at the correct petrophysical answer. 


When Conrad and Marcel Schlumberger invented the technique of well logging, low-resistivity pay was, practically speaking, a contradiction in terms. Their pioneering research hinged on the principle that gas-or oil-filled rocks have a higher resistivity than water-filled rocks. Through the years, however, low-resistivity pay has become recognized as a worldwide phenomenon, occuring in basins from the North Sea and Indonesia to West Africa and Alaska. With low oil prices driving the reexploration of mature fields, methods of intepreting low-resistivity pay have proliferated. 

This article examines the causes of low-resistivity pay in sands, then explores the tools and techniques that have been developed to evaluate such zones. A case study shows how log/core integration helps pinpoint the causes of low-resistivity pay in the Gandhar field in India. 











 
 Generally, deep-resistivity logs in low-resistivity pay read 0.5 to 5 ohm-m. "Low contrast" is often used in conjunction with low resistivity, indicating a lack of resistivity contrast between sands and adjacent shales. Although not the focus of this article, low-contrast pay occurs mainly when formation waters are fresh or of low salinity. As a result, resisitivity values are not necessarily low, but there is little resistivity contrast between oil and water zones.


Becauses of its inherent conductivity, clay, and hence shale, is the primary cause of low-resistivity pay. How clay contributes to low-resistivity readings depends on the type, volume and distribution of clay in the formation.

Clay minerals have a substantial negative surface charge that causes log resistivity values to plummet. This negative surface charge - the result of substitution in the clay lattice of atoms with lower positive valence - attracts cations such as Na and K when the clay is dry. When the clay is immersed in water, cations are released, increasing the water conductivity.


The cation exchange capacity, or CEC, expressed in units of milliequivalent per 100 grams of dry clay, measures the ability of a clay to release cations. Clays with a high CE will have a greater impact on lowering resistivity than those with a low CE. For example, montmorillonite, also known as smectite, has a CEC of 80 to 150 meq/100 g whereas the CEC of kaolinite is only 3 to 15 meq/100g.

Clays are distributed in the formation three ways: 
  • laminar shales- shale layers between sand layers
  • dispersed clays- clays throughout the sand, coating the sand grains or filling the pore space between sand grains
  • Structural clays- clay grains or nodules in the formation matrix





Laminar shales form during deposition, interspersed in otherwise clean sands. In the Gulf Coast, USA, finely layered sandstone-shale intervals, or thin beds, make up about half the low-resistivity zones. Many logging tools lack the vertical resolution to resolve resistivity values for individual thin beds of sand and shale. Instead, the tools give an average resistivity measurement over the bedded sequence, lower in some zones, higher in others.  




Intervals with dispersed clays are formed during the deposition of individual clay particles or masses of clay. Dispersed clays can result from postdepositional processes, such as burrowing and diagenesis. The size difference between dispersed clay grains and framework grains allows the dispersed clay grains to line or fill the pore throats between framework grains. When clay coats the sand  grains, the irreducible water saturation of the formation increases, dramatically lowering resistivity values. If such zones are completed, however, water-free hydrocarbons can be produced.

Structural clay occur when framework grains and fragments of shale or claystone, with a grain size equal to or larger than the framework grains, are deposited simultaneously. Alternatively, in the case of selective replacement, diagenesis can transform framework grains, like feldspar into clay. Unlike dispersed clays, structural clays act as framework grains without altering reservoir properties. None of the pore space is occupied by clay.

Other causes of low-resistivity pay include small grain size and conductive minerals like pyrite. Small grain size can result in low resistivity values over an interval, despite uniform mineralogy and clay content. The increased surface area associated with finer grains holds more irreducible water, and as with clay-coated grains, the increasing water saturation reduces resistivity readings. Intervals of igneous and metamorphic rock fragments - all fine grained- mimic the log signature of clays, featuring high gamma ray, low resistivity and litte or no spontaneous potential (SP). Unlike thin beds, this type of low-resistivity pay can vary in thickness from milllimeters to hunderds of meters.

Finally, sands with more than 7% by volume of pyrite, which has a conductivity greater than or equal to that of formation water, also produce low-resistivity readings. This type of low-resistivity pay is considered rare. 

The challenge for interpreting low-resisitivity sands hinges on extracting the correct measurement of formation resistivity, estimating shaliness and then accurately deriving water saturation, typically obtained from some modification of Archie's law. Improved vertical resolution of logging tools and data processing techniques are helping to tackle thin beds. Nuclear magnetic resonance (NMR) logging shows promise for assessing irreducible water saturation associated with clays and reduced grain size. And because the most opportune time to measure resistivity occurs during drilling, when invasion effects are minimal, resistivity measurements at the drill bit also play an important role in diagnosing low-resistivity pay. 

Thin Beds

One obvious method for resolving the resistivity of thin beds is to develop logging tools with higher vertical resolution, deeper depth of investigation, or both. Two logging devices that have proved especially helpful in evaluating thin beds are the AIT Array Induction Imager Tool and the FMI Fullbore Formation MicroImager tool. The AIT tool uses eight induction-coil arrays operating at multiple frequencies to generate a family of five resistivity logs. The logs have median depths of investigation of 10,20,30,60 and 90 in. and vertical resolution of 1 ft, 2 ft and 4 ft. The FMI tool images the borehole with an array of 192 button sensors mounted on four pads and four flaps. It has a vertical resolution of 0.2 in. [ 5 mm ] .

Successive improvements in resolving  thin beds are strikingly visible in a series of logs made 33 years apart in adjacent wells in the South Texas Vicksburg formation. In 1960, induction/ short normal logs indicated 7 ft of net gas pay and only two beds with resistivity greater than 2 ohm-m. In 1993, a new well was drilled within 100 ft [30 m] of the original well and logged with conventional wireline tools. The induction/SFL Spherically Focused Resistivity logs doubled the estimated pay to 14 ft [4.3 m], with seven beds above 2 ohm-m. Later the same year, the second well was logged with a combination of AIT and IPL Integrated Porosity Lithology tools. The high resolution of the AIT tool - 1 ft versus 2 ft for the induction- and the enhanced sensitivity of the IPL-derived neutron porosity increased net pay to 63 ft [19.2 m] and showed 13 beds with resistivity greater than 2 ohm-m.

Resistivity Measurements at the Bit

Improvements in mesurements-while-drilling (MWD) technology have not only boosted the efficiency of directional drilling, but also enhanced thin-bed evaluation. Two tools, the RAB Resistivity-At-the-Bit tool and the ARC5 Array Resistivity Compensated tool - are especially useful in thin-bed environments by providing resistivity data before invasion has altered the formation.

The RAB tool provides five different resistivity readings plus gamma ray, shock and tool inclination measurements. Configured as a stabilizer or a slick collar, the RAB tool is run behind the bit in a rotary drilling assembly and above the motor in a steerable drilling assembly.

One resistivity measurement, called "bit resistivity" , uses the drill bit as part of the transmitting electrode. With the RAB tool attached to the bit, alternating current is circulated through the collar, bit and formation before returning to the drillpipe and drill collar above the transmitter. In the case of oil-base mud, which is an insulator, the current loop is complete only when the collars and stabilizers touch the borehole wall. The vertical resolution of the RAB bit resistivity is only 2 ft and it gives the earliest possible warning of changes in formation resistivity.

Four additional resistivity measurements, with 1-in. vertical resolution for thin-bed applications, are made with three button electrodes and a ring electrode. The shallow depths of investigation- 3, 6 and 9 in. for the buttons and 12 in. for the ring electrode- allow interpreters to characterize early-time invasion.










The recently-introduced ARC5 tool provides five phase and attenuation resistivity measurements, like the AIT tool, with a vertical resolution of 2 ft. With a 4 3/4 in. diameter, it is especially useful for formation evaluation in slim holes typical of deviated drilling. 


 The measurements and spacings of the ARC5 and AIT tools are comparable, although not identical, making petrophysical evaluation with either tool in the same well or between wells seamless. The multiple measurements of the ARC5 tool also allow interpreters to radially map out the invasion process. The additional phase and attenuation measurements provide a better characterization of electrical anisotropy than existing MWD tools.

Improving Thin-Bed Evaluation Through Data Processing

Despite the emphasis on developing high-resolution resistivity logging tools, many openhole tools still have a vertical resolution of 2 to 8 ft [ 0.6 to 2.4 m] . Several data processing techniques have been developed to enhance the vertical resolution of these traditional tools. All methods use at least one high-resolution measurement to sharpen a low-resolution measurement to sharpen a low-resolution one and require a strong correlation between the two. 

SHARP analysis relies on high-resolution inputs, such as Formation MicroScanner, FMI, or EPT Electromagnetic Propagation Tool logs to define a layered model of the formation. The program looks at the zero crossings on the second derivative of the high-resolution log, where the slope changes sign, to indicate bed boundaries. In the case of a Formation MicroScanner or FMI log, the SHARP program examines the second derivative of an average resistivity reading from all button sensors.


With bed boundaries established, SHARP analysis plots a histogram of the frequency of a particular resistivity value within the logged interval of interest. By styudying how resistivity values cluster an interpreter can group the values into different populations, or modes. 















In addition, SHARP evaluation assumes that petrophysical parameters such as density, neutron porosity and sonic velocity are also constant in a given mode.


When the synthetic and measured logs match, the model can be used as a high-resolution input into the ELAN interpretation. To sharpen the resolution of other logs, such as the gamma ray, the model of bed boundaries determined previously is utilized to reconstruct other squared, enhanced logs for high-resolution formation evaluation. 

Working with logs from the GLT Geochemical Logging Tool, researchers picked a high-resolution clay indicator, either the FMI or EPT log, and calibrated it to the clay volume derived from the  GLT measurement. In addition to clay volume, the GLT tool combines nuclear spectrometry logging measurements to determine mineral concentrations and cation exchange capacity of the formation.


Using Electrical Anisotropy to Find Thin-Bed Pay

James Klein and Paul Martin of ARCO Exploration and Production Technology in Plano, Texas, and David Allen of Schlumberger Wireline & Testing in Sugar Land, Texas are modeling electrical anisotropy to detect low-resistivity, low-contrast pay such as thin beds. The researchers found that a water-wet formation with large variability in grain size is highly anisotropic in the oil leg and isotropic in the water leg. They attribute the resistivity anisotropy to grain-size variations, which affect irreducible water saturation, between the laminations. 

They tested their theory by modeling the thin, interbedded sandstones, siltstones and mudstones of the Kuparuk River formation A-sands of Alaska's North Slope, located 10 miles [16 km] west of Prudhoe Bay. The model, based on a Formation MicroScanner interpretation , contains layers of low-permeability mudstone and layers of permeable sandstone with variable clay content.

The tested their theory by modeling the thin, interbedded sandstones , siltstones and mudstones of the Kuparuk River formation A-sands of Alaska's North Slope , located 10 miles [ 16 km] west of Prudhoe Bay. The model, based on Formation MicroScanner interpretation, contains layers of low-permeability mudstone and layers of permeable sandstone with variable clay content.  

The simulated resistivity data are described as either perpendicular - measured with current flowing perpendicular to the bedding - or parallel- measured with current flowing parallel to the bedding.

Plotting perpendicular versus parallel resistivity for a given interval shows how hydrocarbon saturation influences electric anisotropy. Simulated resistivity data in the oil column curve to the right, but simulated resistivity data in the water leg are nearly linear. The position of data along the oil column indicates the lithology of the formation.


Today, this technique works only with 2-MHz MWD tools such as the CDR Compensated Dual Resistivity tool. The CDR phase and attenuation measurements provide a unique response to anisotropy that allows the perpendicular and parallel resistivities to be determined. The technique requires that the logging tool be parallel to the beds so that differences in the phase and attenuation of resistivity measurements can be used to establish anisotropy. Although the technique cannot yet be applied at other angles, its originators believe some operators will value it enough to tailor the deviation of their wells so that logging tools can run parallel to beds of interest.

Nuclear Magnetic Resonance Logging

Although thin-bed evaluation is challenging, the tools and techniques described so far provide answers in most cases. More troublesome to interpreters than thin beds is another prominent cause of low-resistivity pay, reduced grain size, which contributes to high irreducible water saturations. The CMR Combinable Magnetic Resonance tool shows potential for measuring irreducible water saturation and pore size.

The CMR tool looks at the behavior of hydrogen nuclei-protons-in the presence of a static magnetic field and a pulsed radio frequency (RF) signal. A proton's magnetic moment tends to align with the static field. Over time, the magnetic field gives rise to a net magnetization- more protons aligned in the direction of the applied field than in any other direction.

Applying an RF pulse of the right frequency, amplitude and duration can rotate the net magnetization 90 degree from the static field direction. When the RF pulse is removed, the protons precess in the static magnetic field, emitting a radio signal until they return to their original state. Because the signal strength increases with the number of mobile protons, which increases with fluid content, the signal strength is proportional to the fluid content of the rock. How quickly the signal decays- the relaxation time- gives information about pore sizes and , to some extent, the amount and type of oil.

A CMR log displays distributions of relaxation, or T2 times, which correspond to pore size distributions. The area under a spectrum of T2 times is called CMR porosity.

Unlike previous NMR tools, the CMR tool is a pad-mounted device. Permanent magnets in the tool provide a static magnetic field focused into the formation. The CMR tool's depth of investigation , about 1 inch [ 2.5 cm] , avoids most effects from mudcake or rugosity. Its vertical resolution of 6 inch [15 cm] allows for comparison with high-resolution logs.

A low-resistivity example from  the Delaware formation in West Texas shows how the NMR response allows log interpreters to measure residual oil saturation directly from the CMR log. NMR measurements on core samples from the Delaware formation show that the NMR response will decay within the first 200 milliseconds (msec) if the pores are filled with water. If the pores are filled with oil, however, the signal decays after about 400 msec. 




The T2 distributions in track 4 have been divided into three parts. The area under the T2 curve to the left of the first cutoff, shown as a blue line at 33 msec, represents irreducible water saturation. The area under the curve from 33 msec to 210 msec (red line) represents producible fluid. Above 210 msec, the area under the curve represents oil, presented as a CMR oil show in track 3. This measurement of oil actually refers to residual oil saturation since the CMR tool looks only at the flushed zone.






























































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