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Abstract The acquisition of quality samples from heavy oil reservoirs can be especially critical. It is frequently the case that in these environments the quality of the oil is the single biggest reservoir risk. Therefore a valid fluid sample where accurate measurements of parameters such as gas oil ratio and viscosity can be made is crucial. These sample can be acquired with production tests but, as in many reservoir environments, it is often desirable to acquire these samples with formation tester (WFT) tools. However, heavy oils provide a significant challenge for WFT’s. The oils are of high viscosity which results in large drawdowns while flowing. They are frequently located in shallower, unconsolidated reservoirs where high drawdowns can lead to sand failure. And additionally they can combine with water (from the formation or from the filtrate) to form emulsions that make fluid analysis difficult and can degrade the quality of the acquired sample. In this paper we review the elements required for successfully sampling heavy oil reservoirs with WFT tools. We first consider the pre-job modeling that is performed to predict the drawdowns and flow rates that can be expected from assumed reservoir properties. We then use this information to design the appropriate tool string from the myriad of options available today. We look at the variety of hydraulic pump and displacement unit options that afford a wide range of flow rates and therefore control over drawdown. Additionally we look at the probe and packer configurations that allow a wide variety of flow areas, again giving more control over sandface drawdown. Finally we address the issue of emulsions especially as it applies to downhole fluid analysis and how these can be mitigated. Introduction Of the 9 trillion barrels of oil in place estimated to comprise the world’s endowment, 6 trillion are attributed to the heaviest hydrocarbons. (Alboudwarej 2006) An accurate evaluation of this resource is obviously crucial to its efficient exploitation. This evaluation is usually dependent on the analysis of a representative fluid sample. In this paper we will discuss the challenges faced with sampling heavy crudes with formation testers and the means at our disposal to mitigate these challenges. Before discussing the methods of acquiring such samples we should first define what is meant by heavy oil. Although we commonly refer to heavy oil it is in fact the viscosity and not the density of the oil that provides the challenges in sampling and production. Density is more important downstream as it is the best indicator of the economic value of the oil. However, it is viscosity that most affects the sampling (and production) of heavy oil. Unfortunately, there is no clear correlation between density and viscosity. High paraffin content, light crudes in shallow, cool reservoirs may have higher viscosity than heavier oils in deep, hot reservoirs. While the US Department of Energy (Nethering 1983) defines heavy oil as between 10 and 22.3 API (0.9 – 1.0 g/cc) the techniques we discuss here are not distinct to this type of oil. Firstly, our techniques here are varying applicable across abroad range of conditions and secondly, the very nature of sampling with formation testers often precludes foreknowledge of the fluid type.

In defining the challenges provided in sampling high viscosity oils we note the following frequently encountered characteristics:

- The oil has a high viscosity and will not flow easily - It is often encountered in shallow (and therefore cool) reservoirs that serve to increase viscosity - These shallow reservoirs are often unconsolidated so sands are therefore weak and subject to failure. - Although oil base mud is sometimes encountered the wells are more frequently drilled with water based muds.

This leads to the possibility of oil-water emulsions forming which affects sample quality and complicates downhole fluid analysis.

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Heavy Oil Sampling with Wireline Formation Testers Peter Weinheber, Schlumberger

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Job design, then, is based on balancing flow rate with drawdown such that the viscous oil will flow but the sand does not fail. And in the case where this is not possible then measures to mitigated against sand production must be implemented. In this paper we will discuss options as follows

- Drawdown control (probe and packer selection) - Flow rate control (pump design and selection) - Filtering options (in-line and external) - Emulsion control (FA placement and sampling mode)

Drawdown Control

The equation governing flow rate and drawdown for formation testers is: ∆ · where Δp is the drawdown from formation pressure, Cpf is a constant dependent on probe size and geometry, Q is the flow rate µ is the fluid viscosity and k is formation permeability. The formation parameters µ and k cannot be controlled and the job must be designed around them. Cpf is the geometric factor for the probe. It is generally taken to be 1/4rp where rp is the radius of the circular probe. Equivalent radii are computed for non-circular (elliptical or oval) probes.

The table to the left shows the variance in drawdown

with some commonly available probes. The formation parameters assumed are for a high permeability (1 darcy) high viscosity (100 cp) oil. The 5 cc/s is the lowest flow rate available with a standard pump configuration.

As can be seen the range of control with probes is about a factor of 7, but even with the largest probe available a typical heavy oil scenario will result in a greater than 400 psi drawdown which will almost certainly collapse many unconsolidated heavy oil sands.

To further extend our control of drawdown a non-probe option such as inflatable dual packer must be considered.

Rather than a probe, the inflatable dual packer uses two rubber elements inflated with water or drilling fluid to isolate a specific interval of borehole. The table to the left shows the variance in drawdown with commonly available inflatable packer intervals. Note that the reduction in drawdown is better than an order of magnitude improvement over that of the probe type tools. But an important caveat must be noted: with the large increase in borehole, and therefore formation, encompassed by the inflatable packer considerable more fluid must be pumped in order to clean up.

Flowrate Control

Wireline formation testers use a pumpout module that contains a hydraulic pump to pump hydraulic oil that moves a reciprocating displacement unit (DU) to move formation fluid. Pumpout module design can be customized by choosing the

DU or the hydraulic pump or both. The DU is typically characterized by the volume of fluid moved with each stroke. Volumes range from 485 cc/stroke down to 110 cc/stroke. The DU also serves to multiply the pressure of the hydraulic pump; for that reason they are often referred to by their pressure ability rather than their stroke size. (Jackson 2009)

The hydraulic pump within the pumpout module determines how fast

the DU moves. Hydraulic pumps are characterized by their output of hydraulic oil per rotation of the pump in cc/revolution. The most common type of hydraulic pump is the variable displacement pump where the output varies with pressure applied. Note the black curve in Figure 1. The hydraulic pump output is about 1cc/rev at low pressures and declines to about 3 cc/rev at higher pressures. Fixed Displacement pumps are also

Probe type Probe radius (inches)

Cpf* Δp (psi) assuming k=1000 mD,

µ=100 cp and Q= 5 cc/s Conventional 0.22 5660 2830 psi

Large 0.54 2395 1197 psi

Extra Large 0.80 1556 778 psi

Elliptical 1.45 (equivalent) 856 428 psi

Table 1: Drawdown variation with probe type

Packer Configuration

Interval Length

Δp (psi) assuming k=1000 mD,

µ=100 cp and Q= 5 cc/s Normal 3.2 ft 23 psi

+ one spacer 5.2 ft 18 psi

+ two spacer 8.2 ft 14 psi

+ three spacer 11.2 ft 11 psi

Table 2: Drawdown variation with interval length

Figure 1: Hydraulic pump performance

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available where the output can be fixed to a (relatively) constant value, regardless of the pressure. Three such pumps are shown in Fig. 1 set at 0.1 cc/rev, 0.4 cc/rev and 0.75 cc/rev. Finally, the output of the hydraulic pump (in cc/rev) will then depend on how fast the pump is driven. Speeds typically range from 300 rpm to 2500 rpm. All of this is then related by the pump flow rate equation: / / ·

· _, where FlowRate is the rate at which

formation fluid is moved by the pumpout module, displacement is the output of the hydraulic pump in cc/rev, MotorSpeed is how fast the pump is run and DU_Ratio is the hydraulic ratio of the displacement unit.

DU Stroke

Size DU

Ratio Pump Displacement

at 1 cc/rev Pump Displacement

at 0.3 cc/rev Pump Displacement

at 0.1 cc/rev 300 rpm 2500 rpm 300 rpm 2500 rpm 300 rpm 2500 rpm Std 485 cc 1.2 4.3 cc/s 36 cc/s 1.3 cc/s 11 cc/s 0.4 cc/s 3.6 cc/s HP 366 cc 1.5 3.3 28 1.0 8 0.3 2.8 XHP 170 cc 2.1 2.4 20 0.7 6 0.2 2.0 XXHP 110 cc 2.9 1.7 14 0.5 4 0.2 1.4

Table 3: Pumpout module performance summary

As Table 3 above summarizes, flow rate can range from 36 cc/s to less than 0.2 cc/s, depending on the configuration of DU and hydraulic pump. Note that the choice of pump speed is selectable in real time while downhole.

Filtering

As the preceding shows there is a great degree of control on both flow rate (through pump selection) and on drawdown (through probe and packer selection). However, the possibility of failing the sand may still exist. This is typically due to one of two reasons. Firstly the sand may be so weak as to be not able to sustain any drawdown. Secondly, there may be a conscious decision taken to exceed sand failure strength as the very low flow rates associated with very low drawdown may result in unacceptably long clean-up times. Formation tester pumpout modules are typically limited in their ability to pump significant amounts of produced sands. For this reason several filtering options have been developed to prevent sand from migrating to the pumpout. These broadly divide into either filtering at the inlet (probe or packer) or filtering in-line within the tool.

In applications where a large diameter or extra large diameter probe is deemed sufficient then a gravel packed filter can be employed as in Fig. 2a. (Jackson 2009) Where the inflatable dual packer is required then single and double mesh filters are available in a variety of screen sizes as shown in Fig 2b and 2d. Additionally, these filters can be configured to carry a gravel pack as demonstrated in Fig. 2c.

The above noted options serve to prevent sand from entering the tool. In addition there is the option of an in-line filter that

traps sand after it enters the tool but prior to it reaching the pumpout module. A diagram of the filter is shown in Fig 3. This type of inline filter assembly allows much larger volumes of produced sands to be accumulated in the trap than does filtering at the inlet. The filter operation is based on the change in velocity of the unfiltered fluid when it reaches the filter assembly. The increase in flow area causes a decrease in velocity which results in the drop out of larger solid particles. Additionally, the filter can be bypassed downhole and in real time should plugging occur or if it is deemed desirable that the sampled fluid not pass through the filter debris.

Figure 2: Filtering options

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Emulsions Given that heavy oils are very often sampled

in the presence of water, either in the form of connate water or more commonly in the form of WBM filtrate, the formation of water in oil emulsions is common. Emulsions provide two challenges. Firstly, they impair the quality of the sample. Emulsified samples can sometimes be demulsified by heating the sample and allowing it to sit for a very long time (days to weeks). The water will coalesce and sink to the bottom. If this is not successful then it is possible to spin the sample out in a centrifuge, however HPHT centrifuges are quite rare. There also exist the option to blow down the sample and centrifuge the oil and then do a recombination to perform PVT measurement. This technique is obviously dependent on the quality of the recombination and especially prior knowledge of the gas-oil ratio.

Finally there is the option of using diluents but experimentation is often required to determine the appropriate type and technique also with the risk that excess diluents can contaminate the sample.

Secondly, the presence of emulsions greatly affects the response of NIR spectrometers, the most important downhole fluid

analysis measurement. The emulsion scatters essentially all incoming light and nothing reaches the detectors. It is not even possible to do the basic oil versus water identification. The challenge is then to indentify emulsions and then either prevent or mitigate their effects.

The downhole identification of emulsions while pumping is usually quite straightforward with the fluid analyzers. The

scattering effect blocks all light to the spectrometer detectors and all optical density channels saturate. When the emulsions are forming in the formation or as the fluid is entering the tool the solution is to pump until the water content is low enough to preclude the formation of emulsions. However, emulsions can also be formed by the stroking action of the displacement unit in the pumpout. Separate oil and water phases enter the pumpout but are agitated to an emulsion by the pump action. There are two ways to approach this problem: One is, as previously, to pump until water content is low. The second option is to configure the tool string such that samples are acquired before the pump in a technique known as reverse low shock (Hashem 2007). In the low shock technique the pump is used to pump fluids directly into the chamber. In the reverse low shock technique the pump is used to pull the piston in the chamber down and this draws fluid into the bottle before it passes through the pump and therefore before it become agitated to an emulsion.

In order to identify if the pumpout is causing emulsions it is necessary to place a fluid analyzer before the pumpout

module. If the option for both low shock and reverse low shock samples is required then it is necessary to place a fluid analyzer after the pumpout module as well.

Segregation

A final point to be aware of when sampling heavy oil in the presence of water is the segregation that occurs within the pumpout module. Assuming no emulsion, as an oil-water mix enters the pumpout it is segregated into slugs of water and oil. If the sample chamber is opened on the water slug then no or little oil will be captured. In lighter oils it is usually just a matter of pumping until the flow is mostly oil. However, in heavier oils this can take excessively long times. Options exist to time the opening of the bottle such that the correct slug is captured, however this method is dependent on accurate determination of flow rate which can be difficult at low speeds. Another option is to open multiple bottles at the same time and capture a large volume of fluid that be later separated in the laboratory.

In the following field examples various of the preceding techniques are demonstrated.

Figure 3: Inline filter bottle

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Field Example 1 The first example is from a field in offshore West Africa. The field includes several reservoirs of varying viscosity with current production from the lower viscosity reservoirs. However more than half the estimated original oil in place is in the two shallowest reservoirs, known to be a very heavy oil but the exact specifications of which were never determined as they had never been produced or sampled. An analysis of the situation identified the following challenges:

- Flowing the very viscous crude - Preventing formation failure at the high drawdowns typically associated

with viscous crude - Emulsion formation with the WBM filtrate. This would affect

downhole fluid analysis used to monitor sample quality and could also impact the quality of the sample itself.

With the above challenges in mind a tool string consisting of an inflatable dual packer and two pumpout modules including a special fixed displacement hydraulic pump and XHP DU was proposed. The string additionally had two fluid analyzers straddling the pump in order to monitor the formation of emulsions. The tool string is shown in Fig 4. Some comments on the tool string configuration:

- The upper MS2 is in low shock mode - The upper LFA2 is used to detect if the pump is causing emulsions to

form between the WBM filtrate and the heavy reservoir oil. Additionally, if there is no emulsion but there is still water present then we can monitor oil-water segregation.

- The upper pumpout module (PO2) is configured with an XHP displacement unit and a fixed displacement hydraulic pump. (shop tests of this configuration prior to the job showed a 1cc/s flow rate at 200 psi differential)

- SC_05 is configured as an exit port - SC_01 – SC_04 contain clean water carried from surface for filling the

elements. This will avoid pumping drilling mud through the pump and damaging it.

- MRPO is configured with a HP DU and a variable displacement hydraulic pump to fill elements. It can also be used as a back-up to fill sample chambers, but it is equipped with a Std DU and a variable displacement hydraulic pump so flow rates will be much higher.

- The lower MS1 is configured in reverse low shock mode. In the event that the PO causes emulsions to form, the samples can be acquired below the PO where there is a much better chance of the fluid being emulsion free. Either PO can be used to fill the lower MS1

- The lower LFA will be compared to upper LFA2 to detect and analyze emulsions.

- The MRPA is fitted with 10 inch packers for 12¼ inch hole. Double filters with fine screens are on the inlet.

- HY-PS with XLD probe for pretests.

Fig. 5 shows the pressure and rate history of the pumping sequence with the addition of the internal pressure in the inflatable dual packer elements (PAHP). Some key points to note: The MRPO (POFR curve in green) is used to inflate the packers. The packer is inflated using water carried downhole in the sample chambers to avoid having to pump

Figure 4: Toolstring for Example 1

Figure 5: Flow and pressure history for Example 1

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potentially hostile drilling mud thus damaging the pump. There is an initial inflation to 500 psi and then two subsequent points where the inflate pressured is “topped up” due to expansion and settling of the elements against the formation. MRPO2 (POFR2 curve in purple) is used to flow from the interval. It is kept at a very low rate to ensure minimal drawdown for the reasons discussed earlier. However, towards the end of the pumping cycle with very little sand production occurring it was decided to slowly ramp the flow rate and to include MRPO in the flow from the interval. As can be seen the flow rate becomes spiky and the drawdown varies greatly, implying that the pump is seeing sand production. The rate is slowed back to MRPO2 speeds and the variations disappear. The tiny pressure bumps in the PAQP interval pressure are the bottles being filled. Note that the drawdown during the low rate pumping is only 15 psi from formation pressure.

Data from the fluid analyzers is merged with the pressure data in Fig. 6. Key points are labeled. At point A flow from the interval begins and the red colour in the image tracks is indicating a highly absorbing fluid – assumed to be mud. At point B the mud has cleaned up and we are pumping clean WBM filtrate. This continues until point C where the first sign of oil is seen on the lower fluid analyzer. However, the agitation action of the pump causes this oil water mixture to emulsify and it exits the pump as an emulsion. Just before point D, where we have emulsion out the top of the pumpout and separate oil and water phases entering the bottom, we begin to sample using the sample chambers below the pumpout in reverse low shock mode. Six bottles are filled like this. After filling these bottles, flow continues until the fluid from the formation is essentially all oil at point D. There is now no water to form an emulsion and both the upper and lower fluid analyzers see clean oil. Sampling then progresses and six PVT bottles from the upper MS are filled in low shock mode, along with the 1-gallon chamber. The recovered samples were of excellent quality and laboratory analysis determined the viscosity to be on the order of 500 cP at reservoir conditions, representing some of the most viscous oil sampled with a formation tester in Africa.

Example 2 This example comes from the North Sea. In this well several zones were sampled. Lower viscosity zones were sampled

with a probe type tool but the zone in this example, due to lower permeability and higher viscosity, required the inflatable dual packer in a standard configuration with interval length of 3.2 ft. The flow and pressure history along with the fluid analyzer response is shown in Fig. 7.

The sequence begins with the inflatable packer being filled. Then pumping from the interval starts at about 5 cc/s and then

ramps up in steps to about 15 cc/s. Note that drawdown is increasing over the entire length of the pumping sequence indicating a fairly low mobility environment. Up to about the 3 hr mark we are pumping mud before clear water breaks through. Very quickly after that we start to see oil but it comes in the form of emulsion. Additionally, as the fluid analyzer is above the pumpout module we are seeing segregation and oil-water slugs. After seven hours of pumping there is still significant segregation and slugging occurring. Less than 30% of the pumped fluid is oil while the remainder is a mix of formation water and WBM filtrate. For that reason there is a risk that opening the bottle at the wrong time and capturing the wrong slug could result in a sample bottle full of water instead of oil. Techniques exist to time the capture of the slug (Weinheber 2008) but they are highly dependent on an accurate flow rate determination and are not reliable when the oil cut is below 50%. For that reason and to avoid having to pump for an excessive time all required sample bottles are opened simultaneously. This gives 3 x 450 cc = 1350 cc of chamber to fill and ensures that the total volume recovered will be representative of the oil-water cut while flowing and will give sufficient oil for analysis. This was indeed the case and lab

Figure 6: Pressure, rate and fluid analyzer data from Example 1.

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analysis of the recovered sample indicated an oil of 7 cp. Additionally, sufficient formation water was recovered for water analysis measurements to be made.

Figure 7: Flow, pressure and fluid analysis for Example 2

Conclusions Sampling heavy oils with formation testers will always present unique challenges. High viscosity combined with

unconsolidated sands requires toolstrings optimized to reduce drawdown and still be able to flow sufficient volume in order to clean up. Recent advances in low rate pumpout module configurations combined with increasing inflatable dual packer spacings are allowing the limits to be pushed. The 500 cp oil highlighted here is just one example and extremes of up to 3000 cp (at reservoir)have been successfully sampled. References Alboudwarej H, et al; 2006 Highlighting Heavy Oil; Schlumberger Oilfield Review Volume 18, Number 2, Summer 2006 pp 34-53 Hashem M, Elshah H, Weinheber P, Parasram R, Borman C, Jacobs S; 2007 Low-Level Hydrogen Sulphide Detection using Wireline

Formation Testers, SPWLA Paper K prepared for presentation at the SPWLA 48th Annual Logging Symposium held in Austin, Texas, United States, June 3-6

Jackson R, De Santo I, Weinheber P, Guadagnini E; 2009 Specialized Techniques for Wireline Formation Testing and Sampling in

Unconsolidated Formations in Deepwater Reservoirs; SPE paper 120443 prepared for presentation at the 2009 SPE Middle East Oil & Gas Show and Conference held in the , Kingdom of Bahrain, March 15–18

Nehring R, Hess R, Kamionski M; 1983. The Heavy Oil Resources of the United States. Contract No. R-2496-DOE, Washington, DC

(February 1983) Weinheber P, Gisolf A, Jackson RR, De Santo I; 2008. Optimizing Hardware Options for Maximum Flexibility and Improved Success in

Wireline Formation Testing, Sampling and Downhole Fluid Analysis Operations; SPE paper 119713 prepared for presentation at the Nigeria Annual International Conference and Exhibition, Abuja, Nigeria, August 4-6