Tuesday, April 9, 2019

Borehole Seismic Data

Seismic surveys in the borehole deliver a high-resolution quantitative measure of the seismic response of the surrounding reservoir. Although these measurements may be used alone to image local features, they may also be tied with well data-logs and cores- and then related to more extensive surface seismic data. Advances in borehole geophysics are helping realize the full potential of existing data to create a sharper image of the reservoir. 

It's a matter of resolution. Surface seismic surveys deliver  one of the few quantitative measurements of reservoir properties away from wells, making the technique central to structural mapping of the entire reservoir volume. However, surface seismic waves cannot resolve features smaller than 30 to 40 ft [9 to 12 m] . On the other hand, logs and cores resolve features on the scale of a few feet down to about 6 inches [15 cm]. Reconciling these two measurement scales to get the optimal picture of the reservoir volume is a problem that has long challenged the industry.

Borehole geophysics has a foot in both the logging and surface camps. From the vantage of the wellbore, seismic data often have higher resolution than their surface seismic counterparts. Depths of each borehole receiver are also known, providing a better tie to the formation properties provided by petrophysical, core and other in-situ measurements and relating them to the 3D seismic volume. 

The idea of locating a receiver downhole and a seismic source at surface is not new. For more than half a century, the check shot has helped to correlate time-based surface seismic surveys with depth-based logs. Check shots check the seismic travel time from a surface shot to receivers at selected depth intervals. Subtraction of times, combined with the depth differences, yields vertical interval velocities and thus relates well depths to surface seismic times. 

In vertical seismic profiles (VSPs), the spacing between downhole geophone levels is considerably closer than for check-shot surveys. VSPs use high-quality full waveforms that include reflection information rather than just the time of first arrivals - or first breaks- to create an image of reflections near the wellbore. Building on this technique, 2D reflection images have been obtained by offset and walkaway surveys with sources and receivers in a variety of configurations that address most reservoir problems.

Yet, despite these and other developments, borehole geophysics has for many years failed to gain the status in reservoir characterization that some industry specialists think it deserves. Now, thanks to improved quality and increased confidence in the match between borehole and surface seismic data, borehole geophysics seems to be moving into an increasingly valued position.

Before examining how borehole seismic data are being used to successfully integrate other data, this article will illustrate how the scope of VSP is broadening through the development of horizontal, 3D and through-tubing techniques.

Broadening the Scope of VSP Applications

In the deviated and horizontal wells of the North Sea,the most common type of borehole seismic survey is the vertical-incidence VSP. These are often called walk-above surveys because, as the geophone is moved along the deviated section of borehole, the source is kept vertically above it, "walking above" the well.  In VSP terms, a horizontal well is an extreme version of a deviated well. Like other VSPs, deviated well surveys may be used for locating the well in the 3D surface seismic volume and assessing the quality of surface seismic surveys. Also, the technique may be employed for measuring lateral velocity variations and for imaging faults and structures below the wellbore. 

The following example of a walk-above VSP was carried out in late 1994, in a North Sea well with a 1.2 kilometer horizontal section. There were two main objectives. The first was to measure a suspected lateral velocity anomaly that may have been creating artifacts in the surface seismic data. The second was to obtain a high-resolution seismic image below the deviated portion of the well. An additional objective was to obtain seismic image in the horizontal part of the well.

Data were collected in ther vertical and deviated portions of the cased well

Monday, March 25, 2019

Nuclear Magnetic Resonance Imaging

Although well logging has made major advances over the last 70 years, several important reservoir properties are still not measured in a continous log. Among these are producibility, irreducible water saturation and residual oil saturation. Nuclear magnetic resonance (NMR) logging has long promised to measure these, yet it is only recently that technological developments backed up by sound research into the physics behind the measurements show signs of fulfilling that promise. 

 For nearly 70 years, the oil industry has relied on logging tools to reveal the properties of the subsurface. The arsenal of wireline measurements has grown to allow unprecedented understanding of hydrocarbon reservoirs, but problems persist: a continuous log of permeability remains elusive, pay zones are bypassed and oil is left in the ground. A reliable nuclear magnetic resonance (NMR) measurement may change all that. This article reviews the physics and interpretation of NMR techniques, and examines field examples where NMR logging has been successful. 

 Some Basics

Nuclear magnetic resonance refers to a physical principle- response of nuclei to a magnetic field. Many nuclei have a magnetic moment- they behave like spinning bar magnets. These spinning magnetic nuclei can interact with externally applied magnetic fields, producing measurable signals.

 For most elements the detected signals are small. However, hydrogen has a relatively large magnetic moment and is abundant in both water and hydrocarbon in the pore space of rock. By tuning NMR logging tools to the magnetic resonant frequency of hydrogen, the signal is maximized and can be measured. 

The quantities measured are signal amplitude and decay. NMR signal amplitude is proportional to the number of hydrogen nuclei present and is calibrated to give porosity, free from radioactive sources and free from lithology effects. However, the decay of the NMR signal during each mesurement cycle- called the relaxation time- generates the most excitement among the petrophysical community.

Relaxation times depend on pore sizes. For example, small pores shorten relaxation times- the shortest times corresponding to clay-bound and cappilary-bound water. Large pores allow long relaxation times and contain the most readily producible fluids. Therefore the distribution of relaxation times is a measure of the distribution of pore sizes- a new petrophysical parameter. Relaxation times and their distribution may be interpreted to give other petrophysical parameters such as permeability, producible porosity and irreducible water saturation. Other possible applications include capillary pressure curves, hydrocarbon identification and as an aid to facies analysis.

Two relaxation times and their distributions can be measured during an NMR experiment. Laboratory instruments usually measure longitudinal relaxation time, T1 and T2 distribution, while borehole instruments make the faster measurements of tranverse relaxation time, T2 and T2 distribution. In the rest of this article T2 will mean tranverse relaxation time. 

NMR Applications and Examples

The T2 distribution measured by the Schlumberger CMR Combinable Magnetic Resonance tool, described later, summarizes all the NMR measurements and has several petrophysical applications:
  • T2 distibution mimics pore size distribution in water-saturated rock
  • the area under the distribution curve equals CMR porosity
  • permeability is estimated from logarithmic-mean T2 and CMR porosity
  • empirically derived cutoffs separate the T2 distribution into areas equal to free-liquid porosity and irreducible water porosity.

Application and interpretation of NMR measurement rely on understanding the rock and fluid properties that cause relaxation. With this foundation of the mechanisms of relaxation, the interpretation of T2 distribution becomes straightforward.

T2 Distribution - in porous media, T2 relaxation time is proportional to pore size.  The observed T2 decay is the sum of T2 signalss from hydrogen protons, in many individual pores, relaxing indepedently. The T2 distribution graphically shows the volume of pore fluid associated with each value of T2, and therefore the volume associated with each pore.

Signal processing techniques are used to transform NMR signals into T2 distributions. Processing details are beyond the scope of this article.

In an example taken from a carbonate reservoir, T2 distributions from X340 ft to X405 ft are biased towards the high end of the distribution spectrum indicating large pores. Below X405 ft, the bias is towards the low end of the spectrum, indicating small pores. This not only provides a qualitative feel for which zones are likely to produce, but also helps geologists with facies analysis.

Lithology-independent porosity- Traditional calculations of porosity rely on borehole measurements of density and neutron porosity. Both measurements require environmental corrections and are influenced by lithology and formation fluid. The porosity derived is total porosity, which consists of producible fluids, capillary-bound water and clay-bound water. 

However, CMR porosity is not influenced by lithology and includes only producible fluids and capillary-bound water. This is because hydrogen in rock matrix and in clay-bound water has sufficiently short T2 relaxation times that the signal is lost during the dead time of the tool. 

An example in a clean carbonate formation compares CMR porosity with that derived from the density tool to show lithology independence. The lower half of the interval is predominantly limestone, and density porosity, assuming a limestone matrix , overlays CMR porosity. At X935 ft, the reservoir changes to dolomite and density porosity has to be adjusted to a dolomite matrix to overlay the CMR porosity. If the lithology is not known or if it is complex, CMR porosity gives the best solution. Also, no radioactive sources are used for the measurement, so there are no environmental concerns when logging in bad boreholes. 

Permeability -perhaps the most important feature of NMR logging is the ability to record a real-time permeability log. The potential benefits to oil companies are enormous. Log permeability measurements enable production rates to be predicted, allowing optimization of completion and stimulation programs while decreasing the cost of coring and testing.

Permeability is derived from empirical relationships between NMR porosity and mean values of T2 relaxation times. These relationships were developed from brine permeability measurements and NMR measurements made in laboratory on hundreds of different core samples. The following formula is commonly used:

A cored interval of a well was logged using the CMR tool. The value of C in the CMR permeability model was calculated from core permeability at several depths. After calibration CMR permeability was found to overlay all core permeability points over the whole interval. Over the zone XX41 m to XX49 m the porosity varied little. However, permeability varied considerably from a low of 0.07 md at XX48 m to a high of 10 md at XX43 m. CMR permeability also showed excellent vertical resolution and compared well to that of core values. The value of C used for this well will be applied to subsequent CMR logs in this formation enabling the oil company to reduce coring costs.

Free-fluid index - The value of free-fluid index is determined by applying a cutoff to the T2 relaxation curve. Values above the cutoff indicate large pores potentially capable of producing, and values below indicate small pores containing fluid that is trapped by capillary pressure, incapable of producing.  

 Many experiments have been made on rock samples to verify this assumption. T2 distributions were measured on water-saturated cores before and after they had been centrifuged in air to expel the producible water. The samples were centrifuged under 100 psi to simulate reservoir capillary pressure.  Before centrifuging, the relaxation distribution corresponds to all pore sizes. It seems logical to assume that during centrifuging the large pore spaces empty first. Not surprsingly, the long relaxation times disappeared from the T2 measurement. 

Observations of many sandstone samples showed that a cutoff time of 33 msec of T2 distribuitons would distinguish between free-fluid porosity and capillary-bound water.  For carbonates, relaxation times tend to be three times longer and a cutoff of 100 msec is used. However, both these values will vary if reservoir capillary pressure differs from the 100 psi used on the centrifuged samples. If this is the case, the experiments may be repeated to find cutoff times appropriate to the reservoir. 

In a fine-grained sandstone reservoir example, interpretation of conventional log data showed 70 to 80% water saturation across a shaly sandstone formation. However, on the CMR log most of the T2 distribution falls below the 33-msec cutoff indicating capillary-bound water. Interpretation including CMR data showed that most of the water was irreducible. The well has since been completed producing economic quantities of gas and oil with a low water cut. The water cut may be estimated from the difference between residual water saturation and water saturation from resistivity logs.

 In another example, but this time in a complex carbonate reservoir, the oil company was concerned about water coning during production. CMR log data showed low T2 values below X405 ft indicating small pore sizes. Applying the carbonate cutoff of 100 msec showed that nearly all the water was irreducible, which allowed additional perforation. To date no water coning has occured.

Values for cutoffs can also be tailored to particular reservoirs and help with facies analysis, as in the case of the Thamama group of formations in Abu Dhabi Oil Company Mubarraza field offshore Abu Dhabi, UAE. In this field, classical log interpretation showed water saturation of 10 to 60%. However, some zones produced no water, making completion decisions difficult. Permeability also varied widely even though porosity remained almost constant.  Laboratory measurements were performed on cores to determine whether NMR logging would improve log evaluation. 

 Cores showed a good deal of microporosity holding a large volume of capillary-bound water. Free-fluid porosity was found in the traditional way by centrifuging the water-saturated cores. For this reservoir, however, capillary pressure was known to be 25 psi, so the core samples were centrifuged accordingly. This showed that NMR measurements could provide a good estimate of nonproducing micropores using a T2 cutoff of 190 msec. In addition, permeable grainstone facies could be distinguished from lower-permeability packstones and mudstones with a cutoff of 225 msec.  

Additional Applications

Borehole NMR instruments are shallow-reading devices. In most cases, they measure formation properties in the flushed zone. This has some advantages as mud filtrate properties are well-known and can be measured at the wellsite on surface. When fluid loss during drilling is low, as in the case of low-permeability formations, hydrocarbons may also be present in the flushed zone. In these cases NMR tool may measure fluid properties such as viscosity and so distingish oil from water. 

A published example of the effects of hydrocarbon viscosity comes from Shell's North Belridge diatomite and Brown Shale formations, Bakersfield, California, USA. Both CMR logs and laboratory measurements on cores show two distinct peaks on the T2 distribution curves. The shorter peak, at about 10 msec, originates from water in contact with the diatom surface. The longer peak, at about 150 msec, originates from light oil.  The position of the oil peak correlates roughly with oil viscosity. The area under this peak provides an estimation of oil saturation.

 T2 distribution measurements were also made on crude oil samples having viscosities oof 2.7 cp to 4300 cp. Highly viscous oils have less mobile hydrogen protons and tend to relax quickly. The CMR log showed the T2 oil peak and correctly predicted oil viscosity. It also showed that the upper 150 ft of the diatomite formation undergoes a transition to heavier oil.

Capillary pressure curves, used by reservoir engineers to estimate the percentage of connate water, may also be predicted from T2 distributions. Typically these curves- plots of mercury volume versus pressure- are produced by injecting mercury into core samples. Under low pressure the mercury fills the largest pores and, as pressure increases, progressively smaller pores are filled. The derivate of the capillary pressure curve approximates the T2 distribution. Some differences in shape are expected as mercury injection measures pore throat sizes, whereas NMR measurements respond to the size of pore bodies.

 Other applications and techniques are likely to follow with more complex operations that might involve comparing logs run under different borehole conditions. For example, fluid may be injected into the formation that is designed to kill the water, so that residual oil saturation may be measured. 

Function of a Pulsed Magnetic

The CMR tool is the latest generation Schlumberger NMR tool. The measurement takes place entirely within the formation, eliminating the need to dope mud systems witth magnetite to kill the borehole signal- a big drawback with the old earth-field tools. It uses pulsed-NMR technology, which eliminates the effects of nonuniform static magnetic fields and also increases signal strength. This technology, along with the sidewall design, makes the tool only 14 ft long and readily combinable with other borehole logging tools. 

The skid-type sensor package , mounted on the side of the tool, contains two permanent magnets and a transmiter-receiver antenna. A bowspring ecentralizing arm or powered caliper arm- if run in combination with other logging tools- forces the skid against the borehole wall, effectively removing any upper limit to borehole size. 

An important advantage of the sidewall design is that the effect of conductive mud, which shorts out the antenna on mandrel-type tools, is greatly reduced. What little effect remains is fully corrected by an internal calibration signal. Another advantage is that calibration of NMR porosity is simplified and consist of placing a bottle of water against the skid to simulate 100% porosity. T2 properties of mud filtrate samples required for interpretations corrections- may also be measured at the wellsite in a similar fashion. Finally, the design enables high- resolution logging- a 6-inch long measurement aperture is provided by a focoused magnetic field and antenna.

Two permanent magnets generate the focused magnetic field, which is about 1000 times stronger than the Earth's magnetic field. The magnets are arranged so that the field converges to form a zone of constant strength about one inch inside the formation. NMR measurements take place in this region.  

 By design, the area between the skid and the measurement volume does not contribute to the NMR signal. Coupled with skid geometry, this provides sufficient immunity to the effects of mudcake and hole rugosity. The rugose hole effect is similar to that of other skid-type tools such as the Litho-Density tool.

The measurement sequence starts with a wait time of about 1.3 sec to allow for complete polarization of the hydrogen protons in the formation along the length of the skid. Then the antenna typically transmits a train of 600 magnetic pulses into the formation at 320-msec intervals. Each pulse induces an NMR signal-spin echo-from the aligned hydrogen protons. The antenna also acts as a receiver and records each spin echo amplitude. T2 distribution is derived from the decaying spin echo curve, sometimes called the relaxation curve. 


Thursday, March 21, 2019

Controlling Fluid Loss

A portion of the fluid pumped during a fracturing treatment filters into the surrounding permeable rock matrix. This process, referred to as fluid leakoff or fluid loss, occurs at the fracture face.  The volume of fluid lost does not contribute to extending or widening the fracture. Fluid efficiency is one parameter describing the fluid's ability to create the fracture. As leakoff increases , efficiency decreases. Excessive fluid loss can jeopardize the treatment, increase pumping costs and decrease post-treatment well performance. 

Typically, particulates or other fluid additives are used to reduce leakoff by forming a filter cake- termed an external cake- on the surface of the fracture face. Acting together with the polymer chains, the fluid-loss material blocks the pore throats, effectively preventing invasion into the rock matrix.

 This approach has been applied successfully for decades to low-permeability (< 0.1 md) formations in which polymer and particulate sizes exceed those of the pore throats. In high permeability reservoirs, however, fluid constituents may penetrate into the matrix, forming a damaging internal filter cake. This behavior has prompted mechanistic studies to determine the impact on fracturing treatment performance.

 Classic fluid-loss theory assumes a two-stage, static - or nonflowing-process. As the fracture propagates and fresh formation surfaces are exposed, an initial loss of fluid, called spurt, occurs until an external filter cake is deposited. Once spurt ceases, pressure drop through the filter cake controls further leakoff. For years, researchers have developed fluid-loss control additives under nonflowing conditions based on this theory.

 The conventional assumptions, however, neglect critical factors found under actual dynamic - or flowing- conditions present during fracturing, including the effects of shear stress on both external and internal filter cakes and how fluid-loss additives move toward the fracture face. In high-permeability formations, with an internal filter cake present, most of the resistance to leakoff occurs inside the rock, leaving the external cake subject to erosion by fluid.

 Analysis of fluid loss under dynamic conditions relates external cake thickness to the yield stress of the cake at the fluid interface and the shear stress exerted on the cake by the fluid. These, in turn, depend on the physical properties of the cake and the rheological properties of, and shear rate induced in , the fluid. Whether an external filter cake forms, grows, remains stable or erodes depends on the way these parameters vary and interact over time and spatial orentation.

Similarly, the effectiveness of additives to control fluid depends on two factors: their ability to reach the fracture face quickly and their ability to remain there. The former is governed by the drag force exerted on the particles and the latter by the shear force exerted on them. The larger the ratio of drag to shear , the greater the chance that the particles will remain on the surface. A greter leakoff flux to the wall, smaller particle dimensions and a lower shear rate favor sticking. Promoting higher leakoff for better additive placement seems directly at odds with controlling fluid loss! However, in practice, higher initial leakoff can yield greter overal fluid efficiency. 

To confirm the controlling mechanisms, dynamic fluid-loss tests were conducted  using a slot-flow geometry, determined to be the simplest representation of what occurs in a fracture. To completly describe the process, computer-controlled equipment was constructed to prepare and test fluids under dynamic conditions, subjecting them to the temperature and shear histories found in a fracture. Cores of various lengths were used in the tests to simulate a fracture segment at a fixed distance from the wellbore. As the fracture tip passes a spesific point, spurt occurs and the shear rate reaches maximum. Then, as the fracture widens, the shear stress decreases. In the test apparatus, this is stimulated by decreasing the flow rate with time. Pressure sensors along the core monitor the progress of the polymer front.

Laboratory tests show that , for comparable fluids and rocks with permeabilities of up to 50 md, fluid loss is greater under dynamic conditions than static conditions. Further, examining the impact of shear stress and permeability on the magnitude of fluid loss and the effectiveness of leakoff control additives in high-permeability formations led to five key conclusions.

First, high shear rates can prevent the formation of an external filter cake and result in higher than expected spurt. Second, an internal filter cake controls fluid loss, especially near the fracture tip. Third, the effectiveness of fluid-loss additives increases with formation permeability and decreases with shear rate and fluid viscosity. Fourth, reducing fluid loss means reducing spurt, particularly under high shear conditions and in high-permeability formations. 

The effect of shear depends on the type of fluid and the formation permeability. Typically, above a threshold shear level, no external cake is formed. The magnitude of fluid loss is dependent on the type of polymer and whether it is crosslinked. If the permeability is high enough and the fluid structure degrades with shear, polymer may be able to penetrate the rock matrix.

Dynamic test revealed that commonly used additives were less effective in controlling fluid loss than static test had previously indicated. Also, a direct link between fluid efficiency and shear rate was demonstrated. The higher the fraction of fluid lost under high shear early in the treatment, the higher the total leakoff volume and the lower the efficiency.


Sunday, March 10, 2019

Advance Fracturing Fluids Improve Well Economics

The oil and gas industry has witnessed a revolution in fluids technology for hydraulic fracturing. Starting in the mid 1980s, focused research led to major improvements in the performance of well stimulation fluids. Today, new additives and fluids are extending these capabilities and providing innovative solutions to nagging problems. The results are more efficient and cost-effective treatments for enhancing well production.

 Hydraulic fracturing is one of the oil and gas industry's most complex operations. This technique has been applied worldwide to increase well productivity for nearly 50 years. Fluids are pumped into a well at pressures and flow rates high enough to split the rock and create two opposing cracks extending up to 1000 ft [ 305 m] or more from either side of the borehole. Sand or ceramic particulates, called proppant, are carried by the fluid to pack the fracture, keeping it open once pumping stops and pressure decline.

What defines a successful fracture? It is one that: 

  • is created reliably and cost-effetively
  • provides maximum productivity enhancement 
  • is conductive and stable over time.  

The Rock, the mechanics and the Fluid

Historically, fracturing has been applied primarily to low-permeability- 0.1 to 10 md-  formations with the goal of producing narrow, conductive flow paths that penetrate deep into the reservoir. These less restrictive linear conduits replace radial flow regimes and yield a several-fold production increase. For large-scale treatments, as many as 40 pieces of specialized equipment, with a crew of 50 or more, are required to mix, blend and pump the fluid at more than 50 barrels per minute (bbl/min). Pumping may last eight hours with 1,000,000 gal of fluid and 2,000,000 to 4,000,000 lbm of propant placed in the fracture.

Until recently, treatments were performed almost exclusively on poor producing wells (often to make them economically viable). In the early 1990s, industry focus shifted to good producers and wells with potential for greater financial return. This, in turn, meant an increased emphasis on stimulating high-permeability formations.

The major constraint on production from such reservoirs is formation damage, frequently remedied by matrix acidizing treatments. But acidizing has limitations, and fracturing has found an important niche. The objective in highly permeable foormations is to create short, wide fractures to reach beyond the damage. This is often accomplished by having the proppant bridge, or screen out, at the end, or tip. of the fracture early in the treatment. This "tip screenout" technique is the opposite of what is desired in low-permeability formations  where the tips is ideally the last area to be packed.

 Why the different approach? The answer is found in the relationship between fracture length and the permeability contrast between the fracture and the formation. Where the contrast is large, as for low-permeability reservoirs, longer fractures provide proportionally greater productivity. Where the contrast is small, as in high-permeability formations, greater fracture length provides minimal improvement. Fracture conductivity is, however, directly related to fracture width. Using short- about 100-ft [30 m] - and wide fractures can prove beneficial.

High-permeability formation treatments are on a far reduced scale. Only a few pieces of blending and pumping equipment are required, and pumping times are typically less than one hour, and often only 15 minutes. Fluid is pumped at 15 to 20 bbl/min with a total volume of 10,000 to 20,000 gal and total proppant weight of about 100,000 lbm. This technique has been successful in the North Sea, Middle East, Indonesia, Canada and Alaska, USA.

While fracturing treatments vary widely in scale, each requires the successful integration of many disciplines and technologies, regardless of reservoir type. Rock mechanics experiments on cores, specialized injection testing and well logs provide dat on formation properties. Sophisticated computer software uses these data , along with fluid and well parameters, to simulate fracture initiation and propagation. These results and economic criteria define the optimum treatment design. Process-controlled mixing, blending and high-pressure pumping units execute the treatment. Monitoring and recording devices ensure fluid quality and provide permanent logs of job results. Engineers tracking the progress of the treatment use graphic displays that plot actual pumping parameters against design values to facilitate real-time decision making. Production simulators compare treatment results with expectations, providing valuable feedback for design of the next job.

At the heart of this complex process is the fracturing fluid. The fluid, usually water based, is thickened with high molecular weight polymers, such as guar or hydroxyproply guar. It must be chemically stable and sufficiently viscous to suspend the propant while it is sheared and heated in surface equipment, well tubulars, perforations and the fracture. Otherwise, premature settling of the proppant occurs, jeopardizing the treatment.  A suite of specially designed chemical additives imparts important properties to the fluid. Crosslinkers join polymer chains for greater thickening, fluid-loss agents reduce the rate of filtration into the formation and breakers act to degrade the polymer for removal before the well is placed on production.

The fracture is created by pumping a series of fluid and proppant stages. The first stage , or pad, initiates and propagates the fracture but does not contain proppant. Subsequent stages include proppant in increasing concentrations to extend the fracture and ensure its adequate packing.

Fracturing fluid technology has also developed in stages. Early work focused on identifying which polymers worked best and what concentrations gave adequate proppant transport. Then, research on additives to fine-tune fluid properties hit high gear.

In the past ten years, a more productive research direction has emerged. Oil companies, service companies and polymer manufacturers have concentrated on the basic physical and chemical mechanisms underlying the behavior of fracturing fluids in an attempt to find improved approaches to fluid design and use. This initiative has led to major advances , including higher-performing polymers, simpler fluids, multifunctional additives and continuous, instead of batch, mixing. These developments have had a significant , beneficial impact on the industry.

Recent innovations are extending the state of art in four areas:
  • controlling fluid loss to increase fluid efficiency
  •  extending breaker technology to improve fracture conductivity
  • reducing polymer concentration to improve fracture conductivity
  • eliminating proppant flowback to stabilize fractures.

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.