In search of saturation The importance of saturation measurements is reflected by the time and effort which has been devoted to gathering them. The most fundamental reservoir parameters - oil, gas and water content - are critical factors in determining how each oilfield should be developed. In this article Jean-Louis Chardac, Mario Petricola, Scott Jacobsen and Bob Dennis outline the importance of saturation measurements and reveal how the latest techniques are he lp in g re s e rv o ir e n g in e e rs a n d geoscientists to maximize production and improve total recovery.

S

aturation, the proportion of oil, gas, water and other fluids in a rock, is a crucial factor in formation evaluation. Without saturation values, fluid distribution can not be evaluated and no informed decision can be made on the development of an oil or gas reservoir. When geologists and reservoir engineers talk about oil ‘pools’, it sounds as though there are large ‘bubbles’ of oil in the rock sequence. In reality, the oil and gas in hydrocarbon reservoirs is distributed through the pore space between the sand or carbonate grains which comprise the reservoir layer (figure 2.1). In the best reservoirs this porosity amounts to between 25% and 35% of total volume. This fraction of the reservoir is filled with fluids in variable proportions and, as reservoir conditions change through production, the volumes which each occupies will alter accordingly. For example, as oil is produced, internal fluid pressure drops and, in many reservoirs, this releases gas from solution. Saturation changes are critical to fluid flow and must be carefully monitored to optimize reservoir management, and delay gas or water coning. A great deal of effort has gone into the collection and improvement of saturation measurements. The wide range of equations and models developed over the years underlines the importance of these measurements, and the complexity of interactions between drilling mud, rock, water and hydrocarbons around a borehole. Native metals and graphite conduct electricity, but the vast majority of rockforming minerals are insulators. Electrical current passes through a formation mainly by the movement of ions in pore water. Clearly, therefore, porosity is a critical factor determining resistivity - in short, high porosity means low resistivity values. Fluid saturation can be assessed indirectly by measuring the resistivity or electrical resistance of a rock layer. Some fluids (e.g. gas and oil) have very high resistivities while formation water and shales have low resistivities. These variations can help to discriminate between fluids, but the borehole and surrounding rock layers are complex environments where mixtures of mud, mud filtrate, hydrocarbon, formation water and rock of varying resistivity are encountered. Attempts to understand and model this situation would be difficult enough if the mixture stayed in one place, unfortunately it does not. Fluid properties around every borehole change with time.

(a)

Invasion plans One of the major problems with saturation measurements is invasion - the movement of drilling mud and mud filtrate into the formation (figure 2.2). During drilling, mud is circulated from the surface. Initially the formation is invaded by a process referred to as ‘spurt’ invasion. This occurs as soon as the drill bit exposes fresh rock surfaces, with whole mud flowing directly into the formation, replacing the water which was present in the pore space. However, within a few seconds, the second stage of invasion begins. The drilling mud forms a deposit (mud-cake) on the side of the borehole and mud filtrate (a liquid filtered through the mudcake layer) oozes into the formation. The depth and extent of invasion is controlled by the physical properties of the mud, the original formation fluid, and factors such as porosity and permeability. The mud filtrate invasion can be modelled by resistivity measurements which follow the ‘invasion front’ through the rock. This front is often represented as a single straight line but, in

(b)

Fig. 2.1: Oil and gas fills the pore space between sand or carbonate grains. The interactions between fluids and grains are critical to oil and gas production. Initial fluid saturation and wettability must be determined to predict reservoir behaviour. Rocks may be either water-wet (a) or oil-wet (b).

(a)

(b)

(c)

(d)

Formation water

Quartz grains

Oil

Mud

Fig. 2.2: Fluid distribution within a reservoir changes through time (a to d). Saturation, the relative proportions of fluids in the reservoir will change with time and to model this change correctly it is essential to measure initial oil and water saturations as accurately as possible. This measurement is complicated by mud invasion - during drilling the undisturbed formation is modified by a rapid influx of drilling muds which push oil and formation water away from the well. 22

Middle East Well Evaluation Review

(a)

(b)

thin beds

(c)

(d)

Fresh mud filtrate Original pore fluids

reality, the edges of the invasion zone are usually ragged and its shape varies in response to changing mud properties, formation conditions and borehole geometry, etc. (figure 2.3). During the 1950s, when modern logging techniques and tools were in their infancy, the problem of invasion and water saturation first became apparent. At that time, invasion was seen as an inconvenient environmental effect. The invaded zone (a rock volume around the borehole which has been filled by mud filtrate) affected all shallow-reading tools such as density, neutron porosity and micrologs. When waterbased oil was believed to have displaced oil or gas, the logs from these tools had to be interpreted very carefully. Even deep resistivity logs, designed to record beyond the invaded zone, could not be relied upon in every well and corrections were often necessary to evaluate the true formation resistivity (Rt). In recent years technical advances have helped to change attitudes to invasion. The flushing of oil and gas away from the wellbore presents a perfect opportunity to study fluid displacement within the reservoir. A technique - the ‘moved oil plot’ - has been developed to take advantage of this. This plot compares the volume of water in the invaded and virgin zones. The difference between these values is the volume of hydrocarbon displaced.

Number 17, 1996.

Fig. 2.3: INVASION PLANS: In vertical wells the invasion zone is more or less symmetrical around the borehole, with mud filtrate reaching a similar depth in similar formations either side of the hole (a). In horizontal wells the situation is more complex. Thin beds above and below the borehole will be invaded to a different extent (b) while, in other cases, invasion may be controlled by permeability variations within a reservoir (c) or by gravitational effects (d).

THE LONG ROAD TO SATURATION In 1942 Gus Archie revolutionized the way the oil industry looks at fluid saturation in reservoirs. Before the publication of his ground-breaking paper geoscientists found it difficult and expensive to evaluate water saturation and hydrocarbon reserves. The only reliable method involved coring the formation using oil-base mud and measuring water saturation in the laboratory. Logs measuring a formation’s electrical resistivity were used to identify hydrocarbon-bearing formations but could not evaluate them quantitatively. Archie’s equation relating saturation to porosity and resistivity changed that.

Rt

R

= φm wSn

w

Where Rt = rock resistivity, Rw = water resistivity, φ = porosity, S w = water saturation, m = porosity exponent and n = saturation exponent. Electrical conduction in rocks is mainly through ion movement in pore filling brine. In rocks with open pores ions move easily, giving low resistivity values. In sinuous and restricted pore systems, and those which contain hydrocarbons, the flow of ions is reduced leading to higher resistivity values.

Archie’s equation quantifies these phenomena for clean, consolidated sands with intergranular porosity. While this provides a good solution in clastic rocks, many carbonates, with their different pore geometries and variable size are more difficult to evaluate. The carbonate reservoirs of the Middle East are characterized by mixed wettabilities - micropores are water-wet and filled with irreducible water, while macropores contain oil and may be oilwet. The microporosity systems often dominate resistivity measurements from logs, giving apparent saturation calculations which are inconsistent with production data, e.g. dry oil from a zone with computed Sw greater than 70%. To overcome this problem both porosity systems (and their wettabilities) must be combined in a single equation for carbonate sequences. Recent work in the Middle East has focused on reliable measurements of the proportions of micro- and macro- pores using Nuclear Magnetic Resonance techniques to evaluate pore size distribution (see Microporosity Makes Sense) . G.E. Archie (1942) The Electrical Resistivity Log as an Aid in Determining Some Reservoir Characteristics. Petroleum Transactions of the AIME 146, pp 54-62.

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In reservoir zones where there is fresh mud invasion a characteristic low resistivity zone, a ‘resistivity annulus’, develops. Moving out from the wellbore, logs initially encounter a zone of high resistivity (containing oil and fresh mud filtrate), then the annulus itself (a low resistivity zone containing oil and saline formation water displaced from the previous zone) and finally, the high resistivities of the original formation water/oil mixture. A resistivity annulus probably exists in every pay zone which is drilled with fresh and oil-based mud - so it is vital that the annulus is identified. If the annulus is missed an oil or gas zone may be overlooked. In wells where saline mud is used the low resistivity annulus does not develop. Simplified models indicate the reasons for a low resistivity anomaly (figure 2.4) but do not represent the complex threedimensional distribution of oil, formation water and fresh mud filtrate that mark the saturation and salinity fronts. If detected, the annulus is a clear indication that hydrocarbons are present. However, if the annulus effect develops beyond the detection range of resistivity tools, Rt can not be measured directly and a hydrocarbon zone may be overlooked. This ‘high-low-high’ profile is very important - when successfully recorded it provides values for Rxo and Rt and, more importantly, it indicates the presence of a ‘pay zone’. However, the low resistivity annulus moves away from the wellbore through time (as the mud filtrate continues to push low resistivity formation water away from the well) and, unfortunately, this movement presents yet another obstacle to resistivity measurements. How can we ensure that the annulus is identified (to guarantee seeing a hydrocarbon layer) and measure R t as the undisturbed reservoir zone is pushed further from the well? An annulus located a long way into the formation (70 in. to 80 in. from the wellbore) would give artificially low readings on other deep reading induction curves and, in some cases, may be beyond the maximum depth of investigation (figure 2.5). Fortunately, the AIT* (Array Induction Imager Tool) can record data from a zone centered 90 in. from the borehole - much further than any other deep resistivity logging tool. This depth of penetration increases the probability of identifying an annulus and of obtaining a good value for Rt. A deep induction log taking measurements from the annulus would give values that were too low and an invasion correction would probably be made to account for these low values. However, this would simply push the resistivity value even lower. 24

Fig. 2.4: In reservoir zones invaded by fresh mud a characteristic low resistivity zone, or ‘resistivity annulus’, develops. When an annulus is detected, we can be sure that hydrocarbons are present. However, if the annulus effect develops beyond the detection range of resistivity tools, Rt can not be measured directly and a hydrocarbon zone may be overlooked.

Salinity front

Saturation front

Oil Fresh mud filtrate

Water

Rxo

Rt Resistivity

A ring of resistivity

Rannulus

Distance from wellbore

Medium

Deep

AIT 5 AIT 4 AIT 3 AIT 2 AIT 1

0

20

40

60

80

100

Depth of investigation (inches)

Fig. 2.5: DEEPER UNDERSTANDING: A resistivity annulus located 70 in. to 80 in. from the wellbore could not be identified using deep induction. The deep induction value recorded would be too low and if an invasion correction is made to account for the low reading it will drive the resistivity value even lower.

Middle East Well Evaluation Review

RESOLUTION REVOLUTION Thin beds (figure 2.6) present some unique logging problems. Enhancements and elaborate processing of logs have gone some of the way to overcoming the thin bed problem. Induction measurements are fundamental to formation evaluation and, because of this, a great deal of effort has been focused on enhancing these logs. The methods involved generally concentrate either on signal processing or hardware improvements. One of the most important signal modification methods is deconvolution. The measurement which appears on a log is a convolved or ‘smoothed’ average of formation property variations (figure 2.7a). Deconvolution extracts actual depth variation of a formation property (such as resistivity) by using information on tool physics to sharpen this vertically averaged measurement (figure 2.7b). The key to this process is knowing how the tool responds to a vanishingly thin bed - the tool's vertical response function (VRF). Once this has been identified, it can be reversed and the log deconvolved to reveal unaveraged formation properties. Deconvolution must be carried out with care. The process usually increases noise and inaccurate results can be generated by mathematical instabilities.

Egyptian vision Many of the oil and gas reservoirs in Egypt's Western Desert are complex. The Bahariya Formation, one of the most important hydrocarbon units in the region, is a prime example. The formation is heterogeneous, mineralogically complex and very thinly layered (figure 2.8).

50

(a) 1

Depth (ft)

100

Standard induction ohm-m 1000

Fig. 2.6: THINK THIN: Thin beds can be a major problem in reservoir sequences. Alternations of porous and tight rock types can alter well and reservoir performance dramatically - leading to unpredictable early water production in some zones.

Agiba Petroleum Company overcame these problems by adopting the latest advanced logging and interpretation techniques. High-resolution resistivity imaging, coupled with saturation imaging, gave a clearer indication of radial fluid distribution around the borehole. The radial coverage gave good permeability indications and contributed to a more realistic invasion model. The AIT tool provides more than resistivity measurements, it also monitors borehole environment. This has two benefits; the inputs required by the environmental correction algorithms are measured rather than estimated and output logs are corrected in real-time. These real-time environmental corrections and R t calculations allow rapid decisions based on high-quality data.

(b) Enhanced induction ohm-m 1 1000

Fig. 2.7: MODEL PERFORMANCE: Formation model with marked changes in resistivity. The standard log (a) can not identify subtle changes and misses some peaks completely. The enhanced log (b) identifies almost every bed; the thinnest being about 2 ft thick.

The ability to do all necessary processing at the wellsite helps to accelerate the entire evaluation process in complex reservoirs. As vertical resolution improves, borehole effects become more pronounced. This is a major problem in bad borehole conditions, particularly if very saline (conductive) borehole fluids are present. For one well in the Meleiha Field, Agiba processed their data at all three resolutions. The well was drilled with water base mud. Borehole conditions were fine and the logs were free from unwanted borehole effects. At 4 ft resolution the logs are characterized by a very smooth response, similar to conventional induction logs, with few of the Bahariya Formation's thin layers being detected. At 2 ft resolution the logs show a lot more detail, including the thin beds that were missing in the 4 ft log. The 1 ft resolution gives the thin bed information and provides a more accurate estimate of resistivity.

150

200 Number 17, 1996.

Fig. 2.8: THIN BED BAHARIYA: The Bahariya Formation in Egypt's Western Desert is a heterogeneous, mineralogically complex sequence of thin beds - in other words, a log analyst's nightmare. 25

Fig. 2.9: Borehole corrections must be carried out on the AIT tool's 28 signals before they can be combined to form logs. The corrections are encoded as tables for various borehole conditions. The tables were developed by finite element modelling of the correction. This complex 3D problem required two years of Cray computer time to solve.

Using the AIT tool, a resistivity annulus can be identified more readily, and the use of Tornado charts for correction can be avoided. The AIT tool was designed to tackle three important problems: • caving/borehole effects; • invasion description; • poor vertical resolution. The AIT tool offers five fixed depths of investigation, but the measurements are not taken from single points in the formation, but from areas that centre on points 10, 20, 30, 60 or 90 inches into it. Sampling at five depths of investigation offers many advantages over results from just three depths. The high-low-high resistivity variations we need to define an annulus are more likely to be identified by five separate measurements which can ‘see’ deeper into the formation. The AIT tool eases the analyst’s burden - making 28 measurements and using built-in borehole correction tables for various borehole conditions (figure 2.9). The latest development in AIT tool technology has been specifically designed for the Platform Express* system. It offers the same five depths of measurement but total tool length is only 16 ft. The problem of erratic ‘stick-slip’ motion encountered in some multiarray induction tools has been solved by adding an accelerometer to provide real-time depth correction for every tool on the string; this also ensures that the tools are ‘ondepth’ with each other. New algorithms have been developed and tested for a range of difficult logging conditions. One of these gives better readings in rugose boreholes and conductive (saline) mud. Additional features include correction to the resistivity logs for dip or deviation up to 60°, and more accurate estimates of Rt in the presence of annulus.

26

However, when the annulus has moved too far into the formation and has passed beyond the maximum depth of investigation for any available tool, direct measurement of Rt is prevented. Clearly, if R t cannot be measured directly, an estimation technique must be devised. Experts are currently working on methods which will allow them to invert resistivity profiles to obtain Rt and Rxo mathematically, using five measurements to evaluate five unknowns. At present, this cannot be done quantitatively. In addition to annulus identification, the AIT tool helps to identify thin beds. Many geoscientists are reaching the conclusion that thin bed analysis is important in every reservoir. The majority of ‘thick’ reservoir intervals are usually layered made up of similar, but distinct thinner units (figure 2.10). By identifying the minor lithological contrasts which define thin layers, it is possible to improve reservoir models and so enhance the predictions which are based upon them.

When the resistivity of the invaded zone is much lower than in the undisturbed reservoir, the ARI* (Azimuthal Resistivity Imager) tool or standard dual laterolog will give a more accurate determination of resistivity than the AIT tool. It is, therefore, important to assess resistivity contrasts before selecting tools. In many Middle East reservoirs resistivity contrasts mean that induction readings are needed in the water layer, to determine Rw (water resistivity) as accurately as possible. When this is the case, induction tools give the best results for deep true resistivity. Accurate resistivity measurements in water zones can be vital. Indications of saturation within the zone will influence major economic decisions in the development of a reservoir. For complete evaluation both types of tool can be run together and this arrangement would be of benefit in most Middle East reservoirs. In practice, however, a choice is generally made and one or other measurement is given priority.

Fig. 2.10: The majority of ‘thick’ reservoir layers are actually sequences of lithologically similar thin beds. Identifying the minor differences between these layers improves the reservoir model and, therefore, the quality of predictions and simulations based upon it. (Denise Stone, AMOCO.)

Middle East Well Evaluation Review

The AIT tool acquires data at three vertical resolutions, but it is usually displayed at the highest (1 ft) resolution (figure 2.11). In wells where conditions are not good for resistivity determination, for example where borehole conductivity is high or the borehole is extremely rugose, there are no benefits from processing data to display the highest resolution and logs are usually displayed at 2 ft or 4 ft resolution. However, even at a vertical resolution of 4 ft, the AIT is about twice as good as other standard fixed focus induction tools, an important factor when investigating thin beds with high resistivity. The choice of vertical resolution at which the log will be processed depends on factors such as hole size and shape, and the expected range of deep resistivities. In difficult environments the operator may decide to select a lower processing resolution to make the data more robust.

Sense and sensitivity Calibration of the AIT tool requires a ‘zero conductivity’ environment, or conditions which approximate this as closely as possible. The process is carried out at special facilities, using equipment which contains no metallic components. During calibration there must be no metal within 28 ft of the tool and there should be no stray electrical signals (e.g. the charges which build up during a thunderstorm) to affect the settings. This extreme sensitivity may seem inconvenient above ground, but when the tool is where it belongs - in the borehole - it can detect the smallest fluctuations. In many cases it could be beneficial to run a FMI* (Fullbore Formation MicroImager) or FMS (Formation MicroScanner*) below the induction tool. The AIT is the only induction tool that can function in this configuration. A through-wire sonde was specially developed for the AIT tool which allows other tools to be run below it in the string. This seemingly simple task required a great deal of engineering effort. The AIT tool's conductivity measurements detect minute voltage changes and electrical connections running through the sonde were likely to cause major problems unless the tools could be shielded to eliminate their influence. Schlumberger has developed a method which allows other tools to be linked below the AIT tool without affecting the very low signal levels measured by the induction tool. This allows for greater flexibility when a tool string is being put together.

Number 17, 1996.

For the first time, tools such as the FMI or FMS can be run in conjunction with an induction log. Careful choice of scales allows the operator to incorporate FMI or FMS images into AIT images of resistivity, Rwa or saturation without excessive distortion.

In too deep In vertical wells, the assumption of symmetry around the borehole encouraged the development of tools that looked deeper into the formation as analysts sought to measure values beyond the zone invaded by mud filtrate. This

‘deeper is better’ philosophy is justified in vertical wells, where the AIT tool can ‘see’ beyond the mud filtrate and measure R t directly. Unfortunately, the radial symmetry that is assumed in vertical wells simply does not exist in highlydeviated and horizontal wells (see figure 2.3). This asymmetry around the tool is a problem. Induction tools measure σ (the conductivity of a bed) and interpretation is based on a constant induced conductivity along the measurement loop. However, when the tool cuts different layers (each having different conductivities) a polarisation effect distorts the readings.

Fig. 2.11: This figure shows a saturation map obtained from the AIT tool and porosity logs. The option of running borehole imaging tools, such as the FMI and FMS, in conjunction with an induction log will improve downhole efficiency.

27

MICROPOROSITY MAKES SENSE

28

z B0 field

z Precessing magnetic moments

B0 field

B1 field Net magnetization along z-axis y

y

x

x

Rock grain

Fig. 2.13: Aligned protons are ‘tipped’ 90° by a magnetic pulse oscillating at the resonance or Larmor frequency.

Rock grain

Rock grain

Fig. 2.12: Proton alignment is the first step in NMR measurement. Spinning protons are aligned using powerful permanent magnets. The protons precess around an axis parallel to the B0 direction. In logging, B0 is perpendicular to the borehole axis.

Rock grain

Rock grain

Rock grain

Small pore

Large pore Amplitude

Amplitude

Over the past year a new generation of Nuclear Magnetic Resonance (NMR) tools has been introduced in the Middle East. These tools, in contrast to the previous generation, no longer require mud doping to kill the borehole signal and this makes the technique applicable in many more wells. NMR measurements are made by manipulating hydrogen protons in fluid molecules. In a sense, the protons behave as small bar magnets - their orientations can be controlled by changes in a magnetic field. A measurement sequence starts with alignment of protons using powerful permanent magnets (figure 2.12). The next step is spin tipping. With the strong magnetic field B0 still applied, the aligned H nuclei are tipped away from B0 by applying a highfrequency oscillating magnetic field B1, perpendicular to B0 (figure 2.13). The H nuclei, now tipped in a plane perpendicular to B0, rotate or ‘precess’ around the B0 axis. If the field B0 was perfectly homogeneous, all of the nuclei would rotate in phase at a frequency called the Larmor frequency. In reality, some of the nuclei will collide with pore walls (figure 2.14) and move back towards the B0 direction while others may stay in the plane of precession but be completely out of phase with the rest of the nuclei. A measurement of the small magnetic field generated by the nuclei rotating in phase will, therefore, decay as more and more nuclei slip out of phase. In the laboratory the longitudinal relaxation time (T1) is usually evaluated but in the wellbore the transverse relaxation time (T2) is measured instead. Both are directly related to pore size (figure 2.14) but T2 is easier to measure in a logging environment. The theory set out above is complicated by conditions in the oilfield. Homogeneous magnetic fields can be approximated in the laboratory, but not in a borehole. The frequency of precession is controlled by the magnitude of B0 and it varies as B0 changes. Consequently, inhomogeneities in the field strength create regions where the nuclei rotate at different frequencies and are no longer in phase. To counteract this ‘dephasing’ problem special sequences called CPMG have been designed to re-focus those nuclei which were no longer contributing to the measured signal, even though they remained in the plane perpendicular to B 0 and were precessing without interacting with the rock surface.

Time, msec

Time, msec

Fig. 2.14: COLLISION COURSE: Precessing protons move about the pore space colliding with other protons and with the grain surfaces. At every collision there is a possibility of a relaxation interaction. Grain surface relaxation is the most important process affecting T1 and T2 relaxation times.

Fig. 2.15: TIME TO RELAX: Water in a test tube has a long T2 relaxation time, 3700 msec at 40°C. Relaxation in a vuggy carbonate might approach this value but water in normal pore space has shorter relaxation times. In sandstones relaxation times range from 10 msec to 500 msec. Middle East Well Evaluation Review

Bound fluid

Water

Possible free water

Water

Moved hydrocarbon

Volume of water from RT

Moved hydrocarbon

0.0

25.0

Oil

CMR bound fluid

Perfs 1:200ft X800

(PU)

0.0

Oil 50.0

(PU)

(IN)

3000

Porosity 0.0

Calcite

20

Anhydrite

T2 AMPLITUDE

Dolomite

Diff. Caliper

0.25 -20

Moved oil X900

T2 THRESHOLD 3

Fig. 2.16: UNTROUBLED WATER: The high water saturations recorded in some reservoir zones can be misleading. In this example, conventional logs would suggest that water might flow from this zone. However, the CMR tool shows that the water is bound in the micropores and the zone should flow dry oil. The perforated zone, which included porous zones with high water saturations, produced oil free of water.

Residual oil

Residual oil

Bound irreducible water

Fluid situations In 1995 a comprehensive campaign of NMR measurements was conducted in Abu Dhabi. This involved eight wells and four different operating companies. The project was intended to evaluate the NMR response of Cretaceous and Jurassic carbonates which are the major oil reservoirs across the region. In parallel to the logging campaign, core analysis was performed on samples from five wells. The main application of NMR measurements in the Abu Dhabi study was to understand pore size distribution in reservoir zones, to determine bound fluid volumes and, from this information, improve predictions of the fluids which will flow from any given zone. However, there are a number of major obstacles. Although the relaxation time T2 is faster in rock pores than in a test tube (figure 2.15), reduced logging speeds were necessary to ensure full characterization of the pore volume. The average logging speed for the Abu Dhabi project was between 200-300 feet per hour. Faster logging rates (up to 900 feet per hour) were possible when only bound fluids were assessed; reflecting the fact that these fluids are typically contained in smaller pores.

Number 17, 1996.

Middle East carbonate reservoirs often display mixed wettabilities - their micropores are water wet and filled with irreducible water, while macropores in the rock contain oil and are oil-wet. The microporosity systems often dominate resistivity measurements from logs, giving apparent saturation calculations which are inconsistent with production data, e.g. dry oil may flow from a zone with a computed water saturation greater than 70%. To overcome this problem both porosity systems (and their wettabilities) must be considered for carbonate sequences. This is achieved using the Combinable Magnetic Resonance (CMR*) tool. When saturations are computed using an equation which accounts for the effect of microporosity on the resistivity log a different picture emerges. Ct = Cw φMmM/X Sw nM/X + fmod SwM φµmµ/X Swµnµ/X

The profiles match so well that adjusting the cut-off to get the best possible fit would seem a very good way to select the correct value. This means that any porous interval in this sequence can be perforated and should flow oil without any obvious risk of producing water. When the interval in this example was perforated it flowed dry oil for several months. In the future, for a more complete analysis, it may be advisable to consider the relative permeabilities of the various fluids as a function of saturation but at this early stage simple empirical approaches are more likely to yield useful results than more sophisticated and theoretically rigorous methods.

X

Where: Ct = total conductivity, Cw = water conductivity, φ = porosity, Sw = water saturation, M denotes macroporosity and µ microporosity. Note: fmod Sw depends on the distribution of microporosity in the rock

This calculation reduces the water saturation value slightly and, more importantly, indicates that all of the water is bound. Plotting the CMR-derived bound fluid against the volume of water computed from resistivity, with the special saturation equation, shows a very convincing match (figure 2.16).

M.J.C. Petricola and M.Watfa (1995) Effect of Microporosity in Carbonates: Introduction of a Versatile Saturation Equation. SPE paper 29841 presented at the SPE Middle East Oil Show, Bahrain 1995. M.J.C. Petricola and H. Takezaki (1996) Nuclear Magnetic Resonance Logging: Can it minimize well testing? 7th Abu Dhabi International Petroleum Exhibition and Conference, SPE 36328 1996.

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In addition to the polarisation effect there is an anisotropy effect. In horizontal wells the hole is often situated at the top of a reservoir zone - within a few feet of an oil-shale interface - and deep resistivity readings, influenced by the formation above the interface, are not helpful. The effects of a shale cap rock, for example, will distort the resistivity measurements being taken in an oil reservoir (figure 2.17). In this case a shale with a resistivity of 4 Ωm lies above the reservoir layer. The oil has a resistivity of 200 Ωm, but measurements in a horizontal well located less than 10 ft below the interface would record a value between 40 Ωm and 170 Ωm. There are two possible solutions. • Selection of deep readings in the appropriate direction (e.g. using the Azimuthal Resistivity Imager, ARI* tool). • Shallow readings taken before the effects of invasion have pushed original formation water away from the borehole wall (e.g. using the Resistivity-at-the-Bit, RAB* tool).

A sense of direction Some tool developments have overcome the asymmetry problem in horizontal wells by offering directional measurement. The ARI, for example, makes 12 azimuthal (directional) readings around the circumference of the tool. Where the geometry of the well is understood, it is possible to select readings in the appropriate direction. Resistivity readings of the LLd and LLhr logs can be strongly affected by azimuthal heterogeneities. In heterogeneous formations the ARI tool’s azimuthal imaging can greatly improve resistivity log interpretation - azimuthal resistivity values can be selected and the values obtained used in a model for formation evaluation. This is particularly important in horizontal wells, where the selected measurement can be for the zone below the well or, as is more likely, along the target layer. Figure 2.18 shows ARI and FMI images, displayed with ARI resistivity curves, in a formation which contains some azimuthal heterogeneities. The low resistivity readings at x91.4 m and x92.2 m are clearly different. This reflects the causes - the shallow low reading is a continuous event (a lowresistivity bed) whereas the deeper low resistivity reading is due to a small heterogeneity which is almost certainly confined to the area around the wellbore. This resistivity low would almost certainly be mis-interpreted on a standard, azimuthally-averaged, resistivity log.

1 Depth 1 in feet 1

Input model resistivity

1000

Computed deep induction

1000

Computed medium induction

1000

-10

-5

Shale 4Ωm

0

5

Oil 200Ωm

10

Fig. 2.17: In a horizontal well the effects of nearby layers (in this case a shale cap rock) can distort the resistivity measurements being taken in the oil or gas layer. The shale cap rock with a resistivity of 4 Ωm lies approximately 5 ft above the reservoir layer. The oil resistivity is 200 Ωm, but a horizontal well less than 10 ft below the interface would record a value somewhere between 40 and 170 Ωm.

Looking down The ARI can differentiate between resistivity above, below and in the plane of the borehole. This is extremely useful where anomalous resistivity conditions 30

Fig. 2.18: The combination of ARI and FMI images with ARI resistivity curves clearly indicates that the low resistivity readings at 91.4 m and 92.2 m are caused by different types of heterogeneity. Standard, azimuthally-averaged logs would not reveal this difference. Middle East Well Evaluation Review

Number 17, 1996.

RHOB vs DLT (LLD) Frequency crossplot

100

100

LLD

RHOB vs ARI (LLHR down) Frequency crossplot

LLHR

are encountered - for example when the borehole is approaching a layer where water breakthrough has occurred or is close to a shale layer or crossing tight layers, etc. One benefit of using the ARI tool is illustrated in figure 2.19. The first crossplot shows the ‘ARI down’ resistivity plotted against bulk density while the second shows standard LLd resistivity versus bulk density. The ARI down correlation is clearly better than that from the LLd. The main reason for this is that the ARI down is affected by the same formation as the density since in a horizontal well such as this the weight of the density pad makes it very likely that it will be facing the lower side of the hole. The LLd is reading an average resistivity from around the borehole and produces a resistivity reading which is too low when the formation under the borehole has a high-resistivity and too high when the formation below has a low resistivity. Saturation estimates rely on accurate resistivity values. Using the ARI tool the operator can select the most appropriate direction and, therefore, most realistic value for formation resistivity. The ARI tool has been used in the Middle East to examine low resistivity fractures in an effort to characterize porosity. The challenge of logging horizontal wells remains and ongoing research is aimed at providing the answers. Azimuthally averaged readings are of little use in horizontal wells. LLd, LLs and induction logs, for example, are influenced by beds which are parallel and close to the borehole. This can be crucial to interpretation when a well is steered close to the top of a reservoir. Tools having different depths (or volumes) of investigation may give very different results in the same horizontal well. A density tool, which takes a very shallow reading may indicate sands while a neutron detector may indicate an overlying shale. The quantitative azimuthal image from the ARI tool helps to detect and identify these beds and so allow the most representative reading to be selected from the azimuthal deep resistivity measurements. In practice, resistivity tools are seldom run alone for complete formation evaluation. Laterologs are often combined with microresistivity tools and porosity tools to produce the so-called ‘triple-combo’. These combined strings are often more than 90 ft long and, while they improve efficiency by reducing the number of logging runs, they pose problems in an extended rig up/rig down period, reduced logging speed and the need to drill more rathole (additional depth at bottom of the well) to ensure complete coverage by all three sections of the ‘triple-combo’.

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2.6 2.8 3.0 2.2 2.4 2.0 2.4 2.6 2.8 3.0 RHOB RHOB Fig. 2.19: If a horizontal well is drilled accurately and is located close to the top of a reservoir zone, the important formation properties are those below the well, not an average of properties above and below. These graphs clearly indicate the value of the ARI tool. 2.0

2.2

Flex joint

Fig. 2.20: Flexible joints allow the HALS to ‘hug’ the borehole wall, thereby ensuring accurate measurement as the tool body moves in and out of rough sections. The shorter pad also improves logging results in deviated holes.

Flex joint

A new laterolog tool, the HALS* (High Resolution Azimuthal Laterolog Sonde) has been developed to overcome these problems. Only 16 ft long, HALS is half the length of the dual laterolog, and has an azimuthal resistivity array. Used correctly, directional measurements help to clarify the situation in horizontal wells. This tool has been designed to cope with rough sections and deviated boreholes (figure 2.20). The flexible jointed construction and short pad length help to keep the tool pressed against the borehole wall.

In some sequences, the complexity of lithological variation makes results from a single tool almost useless. In future, efforts may focus on running several resistivity tools during the same logging run; and cross-referencing between them to construct a clear picture of reservoir lithology and relative bed thicknesses. This 3D modelling will require advanced software packages and a better understanding of reservoir geometry.

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The shallow end One alternative to directional or deep measurement of resistivity is to take shallow measurements during drilling - in the very early stages of invasion. It is now possible, using Logging While Drilling (LWD) technology, to measure resistivity at the bit. Field tests conducted with the RAB* (Resistivity-at-the-Bit) tool show that measurements made using the ring electrodes (figure 2.21a) record Rt accurately when run close to the bit (i.e. when the formation is logged before significant invasion effects develop). Its performance has been assessed using deep resistivity tools such as Laterologs. Fig. 2.21: BUTTONS AND RINGS: Using a ring electrode Rt can be measured accurately when the RAB tool is run close to the bit (i.e. when it logs the formation before significant invasion effects develop). The button electrodes measure resistivity at different depths and can help to identify the zones where invasion starts. In the right conditions, they can be used to compute invasion diameter.

When the RAB tool is run some time after the drill bit, the resistivity value is affected by invasion. However, ‘tornado’ charts can provide a reasonable correction in order to determine Rt and calculate saturation. When run directly at the bit and making measurements using the bit itself, the RAB tool provides critical information for geosteering, or for selection of casing and coring points as soon as the formation of interest is penetrated. Sensors located very close to the drill bit detect changes which indicate when a well is about to leave the target zone and move into adjacent shale or water layers.

This allows the driller and geologist to steer a well in real-time, ensuring that as much of the well as possible stays within the reservoir layer. The RAB tool was designed to perform this task and to measure Rt accurately in saline muds with high resistivity formations. In these situations, borehole and invasion effects on the tool are small. The RAB tool has greatly extended the range of conditions where accurate formation resistivity measurements can be made while drilling. It is suitable for very high-resistivity formations, and can make multiple measurements at four depths of investigation.

(a) Transmitter

axial

Ring measure current

Receiver measure current

(b) Ammeter Collar Insulation Ring electrode

Button electrode Ammeter

Cross-section view

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Fig. 2.22: The RAB tool's ring electrode induces a voltage difference in the string, causing current to flow into the formation. As this returns (arrows), it is measured to derive formation resistivity. Button resistivity (red area) delivers good vertical resolution and allows the borehole to be scanned as the tool rotates.

Middle East Well Evaluation Review

Fig. 2.23: DOWNHOLE NAVIGATION: Detailed images of the borehole can be recorded and stored downhole in the RAB tool for later analysis. The imaging facility can be switched on or off, allowing the operator to select specific well intervals for detailed examination.The data transfer rate from tool to surface is the only obstacle to real-time resistivity imaging.

Right on the button The RAB tool’s button electrodes (figure 2.21b) measure resistivity at different depths and can help to identify the zones where invasion starts. In the right conditions, they can be used to compute invasion diameter. As the tool rotates, the RAB buttons take resistivity measurements from around the wellbore (figure 2.22). This azimuthal resistivity data is stored in the RAB tool and can be retrieved when it returns to surface. The image which is generated allows computation of dips, fracture detection and estimation of fracture aperture and orientation. The features shown are similar to those obtained using the ARI tool, but offer better resolution. The RAB button measurements provide a good indication of movability when a sufficient break is allowed after drilling. This, however, conflicts with the objectives of early logging - to establish a value for Rt. One solution is to run two RAB passes, one close to the bit to assess Rt and another after invasion to evaluate movability. Additional resistivity data, including detailed images of the borehole (figure 2.23) can be recorded and stored downhole for later inspection. Detailed resistivity imaging using the button electrodes is possible because the resistivity measurements are made in the very early stages of invasion (figure 2.24). The restricted data transfer rate between tool and surface is the only obstacle to real-time resistivity imaging. Horizontal drilling can be compared to driving your car or taking a bus across a city. The RAB tool offers the freedom of the car driver - the driller and geologist can stop at any time to consult a ‘map’ of changing borehole conditions, take pictures of the borehole as they pass through and change direction to reach the right destination. Traditional horizontal drilling, by comparison, is like falling asleep on the bus and arriving somewhere you may not want to be, with no idea of how you got there.

x015

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x030

x035

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x045

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Drilling mud Invasion front

Fig. 2.24: High quality measurements are possible with the RAB tool because it examines the formation almost as soon as it is drilled while invasion effects are at a minimum.

RAB tool

Number 17, 1996.

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Cased hole choices In cased holes, reservoir evaluation and saturation monitoring are performed in one of two ways. The first method TDT* (Thermal Decay Time principle) measures the decay of thermal neutron populations and the other uses tools such as the RST* (Reservoir Saturation Tool) to assess changes in a reservoir’s fluid saturations. The RST tool contains a minitron - an electronic neutron source - which fires high energy neutrons through the casing and into the rock layers around the borehole. These neutrons interact with the borehole and formation fluids, producing gamma rays. The RST tool measures the returning gamma rays to identify water and oil saturations.

Neutron capture Slow neutron γ-ray Nucleus

Excited nucleus

Inelastic scattering γ-ray

Nucleus Fast neutron

Setting your sights on sigma

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Fig. 2.25: In neutron capture, neutrons are incorporated into the nucleus of the fluid atoms - the gamma-rays released are recorded to derive the Σ measurements. Inelastic scattering with fast neutrons (where the neutron strikes the rock or fluid nucleus but is not captured by it) and associated gamma-ray release, is the basis for C/O measurements.

Excited nucleus

Saline Formation Fig. 2.26: Capture crosssections for various Water 100 Capture cross-section

There are two basic mechanisms which help to identify saturation values - neutron capture and inelastic scattering (figure 2.25). In neutron capture, the high energy neutrons from the minitron source, after slowing down to a thermal energy level, are incorporated into the nucleus of rock or fluid atoms - this is the basis for Σ (sigma) measurements. Inelastic scattering with fast neutrons (where the neutron strikes the rock or fluid nucleus but is not captured by it) is the basis for C/O measurements (see below). The different atoms which comprise oils, formation water, rock etc. capture different amounts of neutrons. This capture value is referred to as the material's capture cross-section. The capture crosssection for formations which contain a lot of high-salinity water is large. Rocks that contain oil and little or no saline water have a low capture cross-section. Typical capture cross-section (Σ) values for salt water are in the range 80 to 100, while the values for oil are usually around 20 (figure 2.26). There is a simple, linear relationship between saturation and Σ which, in ideal conditions, allows a quick and accurate determination. However, there are possible complications. For example, if there is mud filtrate behind the pipe, the Σ values will reflect this and, in non-perforated zones, there is no way to estimate the effect of any residual mud. In perforated zones it is likely that the mud has been removed by the perforation process and the pressure of flowing hydrocarbon, but even here the Σ values can not be relied on entirely. The measured values at and around the perforation reflect a disturbed reservoir state and may not be characteristic of the rest. This problem is particularly acute in the Middle East where perforated zones are often acidized to improve permeability. The acid reacts with the formation car-

80 60 Oil

Injected Water

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atoms can help to characterize the fluid content of formations. The difference between oil’s capture crosssection (around 20) and water (in the range 80 to 100) is a simple way to distinguish reservoir zone from aquifer. However, it is impossible to differentiate between oil and injected water using this method.

20 0 Salinity of pore fluid

bonate to give a high capture cross-section reading with the TDT tool. Consequently, potential oil zones in acidized wells can give a typical water zone reading. This ‘acid effect’ is one of the main reasons why saturation monitoring should take place in observation wells - not producers. In most wells, the Σ values provide a good approximation of saturation. The high-salinity formation water is easily distinguished from hydrocarbons. However, fresh water injected into the well (and, in comparison to formation water, seawater can be considered ‘fresh’) will give values close to those for oil. So, in places where fresh water is being injected another type of measurement is required.

Carbon and oxygen In C/O logging the relative concentrations of carbon and oxygen atoms in the formation fluids are measured to assess saturation. In the past, this method was restricted to relatively shallow depths of investigation, producing results which were difficult to interpret (influenced by the carbon in carbonate minerals, cement etc.) as well as being relatively slow (about 20 ft/hour).

Middle East Well Evaluation Review

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Relative counts

Hydrogen Carbon

106

Oxygen 105

Inelastic water

Fig. 2.27: Inelastic burst spectra. This example shows a test set-up with the tool's far detector immersed in tanks of oil and water. Peaks for carbon atoms (in the oil) and oxygen atoms (in the water) are easily identified.

Inelastic oil

104 0

2

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Energy (MeV) Fig. 2.28: ELEMENTAL FINGERPRINTS: This plot of standard spectra for the RST tool can be used to ‘finger print’ the five elements shown. Although oxygen and carbon are the most important elements for saturation monitoring, the presence of carbon and oxygen in rocks (e.g. limestones) and in cement means that formation corrections may have to be made in order to identify true saturation effects.

Oxygen

Relative counts

Silicon

Calcium

Iron Carbon

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Dual detector COR model for 21/2 in RST tool

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oil ion

yo so

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Number 17, 1996.

water in formation water in formation oil in formation oil in formation

Fig. 2.29: This type of plot is used for interpretation of RST results. This plot shows the expected range of values for a 43 porosity unit limestone formation, with the tool in an 8 1/2 in. borehole with 7 in. casing. All data should fall within the box.

rm at

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il ole o

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w-w: water in borehole o-w: oil in borehole o-o: oil in borehole w-o: water in borehole

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The previous generation of logging tools were large and operated at very slow speeds. An additional problem was their sensitivity to borehole fluid which restricted the use of carbon-oxygen logging. In cases where C/O logging was required, the well usually had to be killed and the production tubing pulled. Given all of these problems and limitations it is not surprising that time and effort was devoted to improving the technique. When there is fresh water in the formation this is the only method that can be used. Hardware improvements and the development of systems, such as the RST tool, have been the main focus of research efforts. The compact design of the RST tool means that a well can be logged quickly without killing the well or pulling the production tubing. The tool can compensate for borehole fluid composition; allowing formation oil saturation to be measured and borehole oil/water fraction to be assessed while the well is flowing.

All the right elements The RST tool can analyze the energy of returning gamma rays to identify chemical elements in the formation. A standard spectrum has been obtained for the tool as a result of extensive testing and this can be used to identify the elements present in the formation. For saturation monitoring, the most important elements are oxygen and carbon which provide information on the presence of water and hydrocarbons respectively (figure 2.27). However, since many rock types contain carbon and oxygen (e.g. limestones CaCO 3 and organic-rich shales), it is important that the elements contained in rock-forming minerals can be identified. Some of the most important rock constituents are calcium, silicon and iron. The RST tool can identify these elements (figure 2.28), give an indication of lithology and, therefore, provide a more accurate assessment of saturation.

A slimhole tonic? The RST tool is available in two sizes small and smaller. The standard RST tool has a diameter of 21/2 inches, while the slim RST tool, measures just 111/16 inches Eliminating the need to kill a well and pull the tubing cuts out the associated risks and minimizes production loss. Interpretation is enhanced because kill fluids do not invade the formation. The smaller RST tool does not offer all of the larger tool’s features, but it is designed for use in shut-in wells. The carbon/oxygen ratios from RST analysis are plotted to assess the probable saturation values for rocks of a particular porosity (figure 2.29). All data should fall within the box defined by the four oil and water values (w-w, o-w, o-o and w-o). 35

THE CATOOSA DRILLING PROJECT In gas-bearing sandstones, mud filtrate invasion is often very deep. When this occurs it can be difficult to discriminate gas-bearing intervals from those containing oil or water. Shaliness and the extreme effects of invasion can mask the familiar ‘gas crossover’ between neutron and density logs. Recorded water saturations can reach 80% in some formations, even with deep resis-

870

AIT resistivity (ohm-m) 10

0.3

tivity measurements. The low resistivity annulus has long been considered a good hydrocarbon indicator, but in some formations the time delay between drilling and logging can mean a very deep annulus which is beyond the investigation depth of standard resistivity logging tools. The resulting low recorded in deep resistivity can lead to an unduly pessimistic evaluation of the well.

Fractional volume 0.2 0.1

0.0

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890

900

ϕ Vsh/2

AO10 AO20 AO30 AO60 AO90

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SFL IMVR IDVR

920

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Fig. 2.30: A direct comparison of AIT and Phasor Induction logs in the Bartlesville sandstone. Porosity and Vshale logs for reference.

Bartlesville Sandstone Petrophysical parameters 10

Rxo Rann RT 10 In

Fig. 2.31: AIT log values as a function of radial depth at the annulus. The annulus position, indicated by the green vertical line, most closely matches the log values in figure 2.30 at the well depth indicated.

20 In 30 In 60 In 90 In

Annulus position at 887ft

The Catoosa drilling project was set up to investigate the effects of different types of mud systems on invasion depth. The drilling and logging were carried out under carefully controlled conditions. The gas-bearing formation selected for the study was the Bartlesville sandstone, a shallow, lowpressured (depleted) section at Amoco's test drilling site in Oklahoma, USA. Three test wells were drilled with different fluid loss control systems. However, some important aspects of log analysis in gas reservoirs were examined. Three wells were drilled with potassium chloride (KCl) mud, one with a high fluid loss, the second with a low fluid loss, while the third was drilled with a partially hydrolized polyacrylamide polymer system (PHPA) - an inhibitive system used to prevent shale sloughing, differential sticking and skin damage. Although this mud system is thought to limit mud filtrate invasion, the invasion depth in this well was greater than in the other test wells. New generation logging tools with new or additional measurements indicated that there were some fundamental problems with the ways in which conventional logs are often used. The neutron-density gas crossover is affected by formation shaliness and can be totally eliminated by an invasion which exceeds 10 in. The AIT resistivity logs indicated that the invasion in all three test wells had formed an annulus and an inversion of the logs allowed an accurate estimate of R t . In one instance (the Bartlesville sandstone) the resulting saturation proved to be one third less than the value derived from the Phasor Induction tool (figure 2.30). In the Bartlesville sandstone the AIT tool’s 60 in. and 90 in. logs are in reverse order - indicating an annulus in this zone. Figure 2.31 shows a plot of the sweep of the annulus inner radius for final saturation values in this unit at 887 ft. This point was chosen because it represented the largest curve separation. Differences in curve separation at other depths are probably due to changes in porosity and depth of invasion.

R.L. Terry, T.D. Barber, S. Jacobsen and K.C. Henry.The Use of Modern Logging Measurements and New Processing Algorithms to Provide Improved Evaluation in

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Deeply Invaded Gas Sands. Presented at the 35th SPWLA Logging Symposium, Tulsa, Oklahoma, USA. June 19-22 1994.

Petrophysical parameters: Sw = 0.35 Sxo = 1.0

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Rw = 0.085 Rmf = 0.98

ϕ = 0.17 Vsh = 0.25

Rsh = 8.5 Rwlrr = 0.025

Middle East Well Evaluation Review

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Fig. 2.32: This crossplot compares near and far carbon/oxygen ratios (with the test well shut in and flowing) with laboratory data for limestone saturated with either oil or water having a density of 0.85 g/cm3.

0.7

Carbon/oxygen ratio (far)

In one example, a well producing from a carbonate reservoir - with porosity between 5pu and 30pu - produced oil with a watercut of about 20%. Figure 2.32 shows a crossplot of the near and far carbon-oxygen data from this well compared with laboratory data for a limestone saturated with water or oil with a density of 0.85g/cm3. The large bounded area shows the dynamic range for a 43pu limestone and the inner area that for a 17pu limestone. Some of the data points fall outside the bounded area - this is due to statistical variations, a borehole which was slightly larger than the assumed 6 in. diameter and a low oil density (0.715g/cm 3 ) at reservoir conditions. The RST can be used for a variety of tasks - reservoir monitoring, detection of water breakthrough and fluid contact monitoring.

0.6 0.5 0.4 0.3 Shut in

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Flowing Lab data 43 p.u.

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Lab data 17 p.u. 0 -0.2

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0.2 0.4 0.6 Carbon/oxygen ratio (near)

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Gas and gravity There are alternative methods for determining gas and oil saturations. In reservoirs where gas is present, gas neutron measurement techniques are used to evaluate the Hydrogen Index within a layer. From this it is possible to derive the gas-oil saturation value. The density contrast between gas and water is the key to the borehole gravimetry technique. It is used to measure gas cap expansion or to track the entry of gas from injection wells - gas displacing oil, not water displacing oil. As oil is produced from a reservoir it is replaced by gas. However, the density contrast to be assessed covers very large areas and the changes which have to be detected call for very accurate measurements.

Fig. 2.33: The combination of ARI and AIT tools will allow the user to establish a 3D picture of formation resistivity, apparent water resistivity and hydrocarbon saturation (from the AIT) and to link these values to wellbore features recorded by the ARI tool.

Enter the third dimension Since the 1950s, research into resistivity tools and techniques has continued without interruption. Many of the analyses which can be made today would have seemed impossible twenty or even ten years ago. However, the oil industry’s appetite for information, gathered more rapidly and with greater accuracy than before, has not yet been satisfied. New software is under development which will combine all of the resistivity tools, including LWD measurements, to derive the best possible resistivity value in all borehole conditions - variable borehole size, formation resistivity, mud resistivity Rt /Rxo contrast etc. However, there are many more possibilities to be explored to make the most of the 3D aspect of the new resistivity measurements provided by tools such as the AIT. For example, running the AIT tool in combination with an ARI tool would allow the use of ARI electrical stand-off and calliper information to refine the AIT borehole correction. Number 17, 1996.

When running together, these tools provide a radial description of resistivity variations (from the AIT) and an azimuthal measurement (from the ARI). If these can be combined, a true 3D representation of resistivity around the wellbore might become available at some future date (figure 2.33). At present, however, there is no software capable of delivering a true 3D resistivity image. Combining both types of logs may be a starting point in the development of this kind of system. If a 3D method could be developed one of the most obvious applications would be in horizontal wells where the resistivity measured on the lower side of the borehole can generally be better correlated with the density/porosity measurements which are themselves affected mainly by the petrophysical properties of rocks and fluids in that location. While it may be some time before true 3D imaging can be developed, the considered combination of radial and azimuthal resistivity information we have at present

will greatly enhance our understanding of invasion and reservoir heterogeneity. Another possibility would be to combine ADN (Azimuthal Density Neutron) and RAB tools. This arrangement has not yet been run in the Middle East, but it would provide four porosities and four resistivity measurements which could be combined to give four saturation values. The pursuit of high-quality saturation data has been a long and difficult process. The new generation of tools and techniques offer a wealth of information which is helping to transform our perceptions of reservoir behaviour.

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