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.