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A novel formation tester for high quality virgin formation fluids sampling and its arrival prediction under deep invasion
Journal of Petroleum Science and Engineering 156 (2017) 697–709
Contents lists available at ScienceDirect
Journal of Petroleum Science and Engineering journal homepage: www.elsevier.com/locate/petrol
A novel formation tester for high quality virgin formation fluids sampling and its arrival prediction under deep invasion Peihu Wang, Lizhi Xiao * State Key Laboratory of Petroleum Resources and Prospecting, China University of Petroleum, Beijing 102249, China
A R T I C L E I N F O
A B S T R A C T
Keywords: Downhole fluids sampling and invasion Time elapse formation resistivity Deep invasion Virgin fluids type detection and prediction
In the past few years, many studies have been focused on how to take virgin formation fluids successfully under increasingly tough formation conditions, such as:
Low permeability zones: Based on field test feedback, traditional probe has difficulty taking formation fluids sample when permeability is less than 1md. By re-designing the probe to increase its surface contact area with the formation; flowrate can be increased significantly which helps in taking formation fluids' samples. It is reported from field that the latest Saturn 3D Radial probe successfully took samples in 0.01md permeability formation because its probe area is around 500 times that of a standard traditional probe. Drilling with oil based mud: Due to oil based mud filtrate mixing with formation oil, it is difficult to take a clean virgin formation fluid sample. For this challenge, the researcher designed a special probe splitting traditional probe's flowline from single flow line into two separate flow lines; a guard line and a sample line to separately draw mud filtrate and virgin formation fluids. Virgin formation fluids collection is totally dependent on the ability to draw the fluid into the probe. Besides low permeability and fluids mixing, deep invasion is another challenge that can hinder the drawing of a clean virgin formation fluid sample. According to experiments and practice in the field, whether virgin formation fluids can be taken successfully depends mainly on the formation permeability. In theory, the higher the permeability, the easier it is to draw formation fluids into formation tester. However, with increasing invasion depths, mud filtrate occupies a bigger area surrounding the borehole and will lead to difficulty for virgin formation fluids breaking through and flowing into formation tester probe. This is because a large amount of mud filtrate will flow into the probe along different orientations. According to this research paper, in order to speed up the formation oil flow into the probe, the permeability heterogeneity plays a very important role. The numeric simulation shows that if formation permeability is more heterogeneous, the virgin formation fluids can be easier to obtain because horizontally oriented fluids will form a dominant flow channel which has a relatively higher velocity compared to the vertically oriented fluids. So, the traditional sampling method becomes increasingly difficult to take virgin formation fluids sample in both low permeability zones and high permeability homogenous zones. To solve the problems facing the ease of pumping virgin formation fluids into the probe, this paper will demonstrate a novel tool design combining traditional formation testing tools and resistivity tools to measure the formation resistivity of virgin fluids sweeping area in real time. By adding electric buttons on the Saturn probe and measuring its voltage trend during pumping, we can obtain 4 different orientations' formation resistivity trends in real time. Through inversion of the formation resistivity of sweeping area nearby borehole, we can estimate virgin formation fluids properties in real time and predict when virgin formation fluids flow into the probe.
* Corresponding author. E-mail addresses: [email protected] (P. Wang), [email protected] (L. Xiao). http://dx.doi.org/10.1016/j.petrol.2017.06.029 Received 12 September 2016; Received in revised form 5 December 2016; Accepted 14 June 2017 Available online 17 June 2017 0920-4105/© 2017 Elsevier B.V. All rights reserved.
P. Wang, L. Xiao
Journal of Petroleum Science and Engineering 156 (2017) 697–709
Darcy law (Kyi et al., 2015), the fluids' flow rate can be expressed as below: In Fig. 1, we know the flow rate (q) has linear relationship with formation property and probe properties. Under particular pressure difference and formation property, more fluids can be drawn with a bigger probe Area (A). This was the focus of most recent research in that area. According to Fig. 2, the latest Saturn 3D radial probe area is around 500 times (Daungkaew et al., 2014; Cig et al., 2014) that of a standard probe area. The Saturn 3D Radial probe was successfully deployed in the Field since 2014, and it was reported that fluids' samples were taken successfully in very low permeability zone (0.01md) (Cai et al., 2014). Compared with standard probe, the Saturn 3D radial probe significantly extends working zone from the lowest permeability 1md to 0.01md. Besides the low permeability application, faster sampling of virgin formation fluids is another main research topic. Due to mud filtrate invasion, traditional probes find it very difficult to take virgin formation fluids because a large volume of filtrate mixed with virgin formation fluid flow into the probe. So, the main benefit of focus probe design is to split traditional probe single flow line into two separate flow lines, a guard line and a sample line with separate flows (Kundu et al., 2007; Nagarajan et al., 2011; Weinheber et al., 2006) (see Fig. 3). Compared to traditional probe design, the guard flow line main focus is drawing mud filtrate and sample flow line only need to draw the fluids in front of it. In theory, the focus probe will be faster than traditional probe to obtain virgin formation fluids. Through analyzing fluids OD trend inside flow line of formation testing tool (Mullins et al., 2000; Zazovsky, 2008; Zuo, 2008; ; Weinheber et al., 2009) during pumping, contamination can be calculated in real time and then it can be predicted when it is good time to take sample.
Fig. 1. Darcy law with formation and probe properties (Probe Area).
1. Introduction 2. Challenges
Since the first generation formation testing tool was deployed into the Field, it was already successfully applied in taking fluids' samples for more than 60 years. In order to minimize potential stuck risks, operators prefer to take virgin formation fluids sample as fast as possible. According to formation testing tool probe design and
The operator needs conventional logs to help to pick up the optimum station to take sample. The well A of Iraq oil field was drilled using water based mud in 2014 (see Fig. 4). After conventional logs analysis, it was
Fig. 2. Surface area comparison in formation testing probe family.
698
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Journal of Petroleum Science and Engineering 156 (2017) 697–709
Fig. 3. Focus probe design and fluids flow path sketch.
Fig. 4. Formation test vs. conventional log plot. 699
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Journal of Petroleum Science and Engineering 156 (2017) 697–709
Fig. 5. Probe Resistivity curve vs. cumulative pump out volume cross plot in station SP-2.
same zone and fluid types should have been similar. We got an oil sample from the station SP-1, but a water sample from SP-2. After analysis, it was thought that invasion depth of SP-2 was deeper than that of station SP-1, which lead to the inability to draw virgin formation fluids from station SP-2 within an appropriate time frame. Based on this real scenario, it was identified that the biggest challenge was the virgin formation fluids inability to be drawn into the probe under deep invasion conditions leading to the inability to estimate virgin fluids type due to sample failure. Besides the real field case, this paper uses numerical simulator (Eclipse) to demonstrate why virgin formation fluids can't be drawn into the probe under deep invasion conditions. Fig. 7 is simulation formation model. Compared with other probes, Saturn 3D Radial probe is faster to obtain virgin formation fluids because it has a bigger surface area. For this simulation, we use this 3D probe with the formation parameters
identified that two stations SP-1 and SP-2 were located in the same zone and with similar fluid properties. The operator decided to take samples from these two stations. After 5 consecutive hours of pumping, an oil sample was successfully taken from station SP-1 which is consistent with conventional logs. While sampling from station SP-2, we couldn't get an oil sample even though 100 L of fluid were pumped out in 6 h. Fig. 5 shows the fluid resistivity only change a little bit and its value is less than 1.0 Ω m until pump stop. It is typical characterization of water. Based on Fig. 6, we found the water channel signal is very high, color channel and oil channel stays constantly lower during the pumping, which indicates that the fluid in the formation tester flow line is water as well. Analyzing probe resistivity and OD trend, it could be concluded that the fluid inside formation tester is water. But from conventional logs' analysis, we knew that the stations SP-2 and SP-1 were located in the
Fig. 6. OD trend with continuous pump volume cross plot in station SP-2. 700
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Journal of Petroleum Science and Engineering 156 (2017) 697–709
orientation formation resistivity. As Fig. 12, the main current (in the middle) will penetrate in the formation as annular electronic beam because there are four focus electrodes surrounding it and emitting focus current to form current shielding layer avoiding main current divergence (see Figs. 11 and 13). 3.2. Measurement principle There are four monitoring electrodes were deployed surrounding the main current to measure voltage. With pumping out time elapsing, the voltage of the four measurement electrodes will change with radial saturation change. From Fig.14, the formation resistivity changes with pump out time elapse. If the zone bears oil, the formation resistivity will increase; otherwise, the formation resistivity will decrease accordingly when formation water has higher salinity than water based mud filtrate (see Fig.15). Fig. 7. Formation model.
3.3. Experiment analysis
shown in Table 1. According to Saturn 3D Radial probe design in Fig. 2, Saturn 3D Radial probe includes 4 probes in different orientations which allow it to separately draw formation fluids from 4 orientations (see Fig. 10). Fig. 8 shows oil saturation distribution when probe draw fluids with constant flow rate 20 cc/s within 6 h. We know the virgin fluids can be drawn into the probe only when horizontal permeability reaches 50 md and vertical permeability was kept as 1md. However, with vertical permeability increase, the virgin formation fluids can't be drawn into probe as well. From Fig. 9, it is shown that permeability heterogeneity plays an important role which directly affect whether virgin formation fluids can be drawn into probe successfully or not. Based on the above simulation results, the deep invasion is the biggest challenge. The reason is that the more homogenous formation is would be lead to a different orientation fluids flowing together into probe so that the fluids in the front of probe can't form a dominant channel to flow into the probe in the limited pumping out time.
Two kinds of sandstone cores were picked up to do oil driven water experiments in the Lab to verify whether numerical simulation results above were reliable or not. The experiment takes traditional single pore system core. The experiment shows core resistance increasing continuously with time elapsed of oil driven water (see Fig.16). For dual porosity system, the core resistance response is same as single porosity system (see Fig.17). Based on the core experiments above, no matter what kind of porosity system, core resistance had consistent response with numerical simulation results. 3.4. Inversion According to ohm's law, the electric field strength is related to electric density and formation resistivity.
E ¼ R⋅J
3. Solution
(1)
The new tool discussed in this paper takes lateral focus emitted current, there are four focus currents forcing main current to penetrate into the formation in a horizontal cylinder shape. Based on this tool's design, the electric density will equal to
Virgin formation fluids can't be drawn into the probe under deep invasion conditions within limited pump out time; this paper will focus on designing a novel tool to estimate fluids' properties by measuring formation resistivity rather than directly measuring fluids' resistivity and then predict when virgin fluids can flow into probe.
J¼
Io 2πhr
(2)
where: 3.1. New tool design Io Main current h The current thickness r The main current distribution radius
According to Saturn 3D Radial probe design, this new tool will be designed to have an ability to measure four orientated formation resistivity. The resistivity measurement takes lateral log principle to measure formation resistivity. The main current will be adjusted by four focus current and it can directly flow into formation. The four measuring electrodes will measure voltage and they are used to calculate different
Because
E¼
du ¼
Table 1 Formation parameters in the simulator. Formation Property
Horizontal(md)
Vertical(md)
Permeability
10 20 50 2 m*2 m*2 m 15%
1 1 1
U
Volume Porosity
du dr
(3)
Io R dr 2πh r U
(4)
U
∫ Umo du þ ∫ Uxom du þ ∫ Utxo du ¼
701
Io Rm rc dr Io Rxo ri dr þ ∫ ∫ 2πh ro r 2πh rc r Io Rt rt dr þ ∫ 2πh ri r
(5)
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Journal of Petroleum Science and Engineering 156 (2017) 697–709
Fig. 8. Formation model mesh and oil saturation distribution after pumping 6 h.
Fig. 9. Oil saturation distribution under different permeability formation.
Io Rm rc Io Rxo ri Io Rt rt ln þ ln þ ln Uo Ut ¼ 2πh ro 2πh rc 2πh ri
as below:
Kd rc Kd ri Kd rt ln ln ln Rm þ Rxo þ Rt 2πh ro 2πh rc 2πh ri
(6) Ra ¼
where:
(8)
Uo : The voltage on the tool face Ut : The voltage of the uninvaded formation ro : Tool radius rc : Well bore radius ri : Invasion radius rt : Uninvaded radius
From equation (8), we know the apparent resistivity is the summation of each formation component resistivity in any particular time (Moinfar et al., 2010; Dalton et al., 2002; Qi et al., 1999; Singha et al., 2012; Charara et al., 2001; Nutt et al., 1989; Gomes et al., 1999; Li and Chen, 2003; Morriss et al., 1996; Mitchell et al., 2010). So, we can reduce equation (8) as to:
Lateral log resistivity can be expressed as below:
Rj ¼
Ra ¼ Kd
ðUo Ut Þ ΔUd ¼ Kd Io Io
(7)
n Kdj X ri Ri *ln 2πh i¼1 ri1
(9)
where:
where:
Rj : The tool measured resistivity of the horizontal resolution j along the radius Kdj : The tool factor of resolution j Ri : The formation resistivity of component i ri : The radius from component i to tool
Kd : Tool electric factor Ra : Apparent resistivity Merging equations (6) and (7), the resistivity can be re-written
Fig. 10. Traditional Saturn 3D Radial probe. 702
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Journal of Petroleum Science and Engineering 156 (2017) 697–709
where: Rw : The formation water resistivity Swi : The saturation of the formation component i During the pumping out period, fluids flow model is spherical flow and the oil flow rate is equal to
vr ¼
Ko dp Ko Pw Pe 1 ¼ μo dr μo 1 1 r 2 Rw Re
(11)
where. Pw : Probe pressure Pe : Formation pressure Rw : Well bore radius Re : Reservoir radius In the given time, the fluids flow distance is equal to:
dr ¼ vr dt
As Fig. 18 described and core experiment, the radial water saturation can be expressed as below:
Fig. 11. Resistivity measurement mounted on the each side of 3D Probe.
8 > > Sw ¼ 1 Sor > > > <
Based Saturn 3D Radial probe fluid suction principle, the formation resistivity changes with radial saturation change because the virgin formation fluids will replace the filtrate invasion area with time elapsing (Huang, 2011; Chassange et al., 2012). For resistivity in each component, it can be expressed by Archie's equation:
Ri ¼
abRw ∅m *Snwi
(12)
Sw ¼ 1 ð1 Swb Þ*e > > > > > : Sw ¼ Swi
r
¼ 1 ð1 Swb Þ*e
ðPw Pe Þ μo 1 1 Rw Re
ð
Þ
Δt r2
ri < r < rt
(13)
r >rt
So, the invasion target is how to calculate ri during the pumping out and predict when the virgin fluids can flow into probe.
(10)
Fig. 12. Main current and focus current contour plot. 703
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Journal of Petroleum Science and Engineering 156 (2017) 697–709
Fig. 13. Current and voltage contour plot.
major purposes were to get samples and predict oil production. In order to achieve these two objectives, the LWD resistivity tool and sampling tools were used. In Fig. 21, the blue curve, including GR and Resistivity track, comes from drilling path. The red curve comes from ream pass. Before sampling, the ream pass GR was measured to locate target zone. Due to the well was drilled by water based mud, the ream pass resistivity is a little bit lower than drilling pass due to water based mud filtrate invasion. In order to get clean oil samples in station 3, there are 30 L fluids pumped out in 3 h. Figs. 22 and 23 show both water based mud filtrate and formation oil are pumped into formation tester tool together. In order to compute oil production more accurate, the fluids mobility need to calculate accurate as well. So, another station 15 was performed below the station 3 but its main purpose is just to obtain drawdown mobility by pretest mode. The green curve in resistivity track shows formation resistivity on
3.5. The synthetic simulation data inversion case analysis During pumping out, the four sink probes will draw formation fluids simultaneously. According to the seepage principle, the fluids flow shape will show spherical in each probe area (see Fig. 19). As Fig. 20 describe, the formation response area will be linear with the distance between negative electrode and focus current electrode. The further the distance between the two electrodes, the deeper of formation component will contribute more to the signals. Apply Tables 2 and 3 parameters into equation (14), we get the invasion depth is 0.2504 m which is very close to model value 0.25 m. 4. Case study for real time formation resistivity response validation in sampling job The appraisal well B was drilled in the x oilfield in 2016. The two
Fig. 14. Measure electrode voltage vs. Elapse pumping out time on oil zone. 704
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Journal of Petroleum Science and Engineering 156 (2017) 697–709
Fig. 15. Measure electrode voltage vs. Elapse pumping out time on water zone.
Fig. 16. Core resistance response with oil driven water under single pore system.
Fig. 17. Core resistance response with oil driven water under dual porosity system. 705
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Journal of Petroleum Science and Engineering 156 (2017) 697–709
Fig. 18. Saturation distribution along well radius.
Fig. 19. Saturn 3D Radial probe spherical flow model.
5. Conclusion
station 15, which is measured by new ream up pass. Comparison with station 3, we found the P34H resistivity curve of station 15 has significantly increasing, which shows the virgin formation oil is drawn into invasion zone to replace part of water based mud filtrate and this is root cause of P34H resistivity measurement increasing. This case shows the time lapse resistivity measurement can help to identify virgin formation fluid type during pumping (see Fig. 24).
● According to simulation results, it was found that formation testing tools can't take virgin formation fluids sample when pumping out time is less than 6 h and if invasion depth is larger than 0.85 m. So, the deep invasion is the biggest challenge for fluids' sampling. ● Through re-designing formation testing tool by applying real-time formation resistivity measurement, we can obtain formation fluids properties in real time and it can help to make decision whether it is needed to continue pumping out to wait for virgin fluids arrival. With real-time formation resistivity help, even no virgin formation fluids flow into probe, data interpreter still can estimate virgin formation fluids type, like oil or water. Compared with traditional formation testing tools, the new tool can mitigate data interpretation uncertainty and improve interpretation accuracy. ● Through real-time measurement of formation resistivity, we can compute invasion depth in real time. By computing invasion depth movement velocity, we can predict how long time is needed to consume when virgin formation fluids flow into probe, which will be
Table 2 Forward modeling parameters table.
Fig. 20. Saturn 3D Radial probe resistivity measurement principle. 706
Formation Component
Resistivity(ohm m)
Radial Depth Interval (m)
Invasion Zone Transition Zone 1 Transition Zone 2 Virgin Zone
1.67 2.5 5 50
0.1–0.25 0.25–0.75 0.75–0.9 0.9~
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Journal of Petroleum Science and Engineering 156 (2017) 697–709
Table 3 Tool Design parameter table & Simulation Data.
Rj ¼
Kdj rd Kd j ri1 Kdj ri2 Kdj rd Kd j ri1 Kdj ri2 ln ln ln ln ln ln Rinvasion þ Rxo1 þ Rxo2 þ 1 Rt 2πh rd 2πh rc 2πh ri1 2πh rc 2πh rd 2πh ri1
(14)
The distance between negative and focus electrode
The voltage of measurement electrode
Tool Factor
The main current(A)
The Apparent Resistivity(ohm.m)
1.25 1.15 1.05 0.95
12.35 12.17 11.96 11.75
0.97 0.94 0.9 0.86
2 2 2 2
5.99 5.72 5.38 5.06
m m m m
V V V V
Fig. 21. Combine LWD resistivity and Sampling log view.
Fig. 22. OD trend with pumping elapse time.
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Journal of Petroleum Science and Engineering 156 (2017) 697–709
Fig. 23. Fluids fraction trend with pumping elapse time.
Fig. 24. Resistivity comparison between drilling pass and ream pass.
used to help operators optimize pump out velocity to mitigate tool stuck risk.
Gomes, R.M.R., et al., 1999. Use of time-lapse resistivity log responses in a horizontal well to understand the evolution of polarization horns and anisotropy. In: SPE Annual Technical Conference and Exhibition. SPE 56450-MS. Huang, H., 2011. Fluid injection experiments in 2D porous media. In: SPE Hydraulic Fracturing Technology Conference and Exhibition. SPE 140502-PA. Kundu, Dibyatanu, et al., 2007. New Wireline Sampling Technique Enables ZERO Contamination Sampling: a Case Study in a Challenging Sampling Environment. SPE 109208. Kyi, K., et al., 2015. Formation Evaluation in Tight Clastic and Carbonate Formations: a Malay Basin Case Study. SPE-175700-MS. Li, Shanjun, Shen, L.C., 2003. Dynamic invasion profiles and time-lapse electrical logs. In: SPWLA 44th Annual Logging Symposium. SPWLA Conference Paper 2003-E. Mitchell, Vanessa, et al., 2010. Inversion of time-lapse electrical resistivity imaging data for monitoring infiltration. In: SEG Denver 2010 Annual Meeting SEG Conference Paper 2010-1950. Moinfar, Ali, et al., 2010. Time-lapse Variations of Multi-component Electrical Resistivity Measurements Acquired in High-angle Wells. SPWLA Journal Paper 2010-V51N6A4. Morriss, S.L., et al., 1996. Time lapse resistivity and water-content changes in shale. In: SPE Annual Technical Conference and Exhibition. SPE 36507-MS. Mullins, Oliver C., et al., 2000. Real-time Determination of Filtrate Contamination during Openhole Wireline Sampling by Optical Spectroscopy. SPE 63071. Nagarajan, N.R., et al., 2011. Reservoir Fluid Sampling of a Wide Spectrum of Fluid Types under Different Conditions: Issues, Challenges, and Solutions. IPTC 14360.
References Cai, J., et al., 2014. New Advances of Formation Testing in Extreme Tight Gas Reservoirs Using New 3D Radial Probe: Case Study in South China Sea. OTC-25032-MS. Charara, M., et al., 2001. Use of permanent resistivity and transient pressure measurement for time-lapse saturation mapping. In: SPE Asia Pacific Improved Oil Recovery Conference. SPE 80433-PA. Chassange, Romain L., et al., 2012. Simulation of drilling filtrate invasion near an observation well. In: EAGE Annual Conference & Exhibition Incorporating SPE EUROPEC 2012. SPE154014-PA. Cig, Koksal, et al., 2014. Improvements of Sampling and Pressure Measurements with a New Wireline Formation Tester Module in Carbonate Reservoirs. IPTC 17159. Dalton, Christopher L., et al., 2002. Real-time, time-lapse resistivity logging with a wired composite tubing. In: SPE Annual Petroleum Conference and Exhibition. SPE 74380MS. Daungkaew, Saifon, et al., 2014. Overcoming Differences between Log and Test Results: a Case-study of Three Appraisal Wells Drilled into Low Contrast Low Resistivity Carbonate Reservoir. IPTC-18228-MS.
708
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Journal of Petroleum Science and Engineering 156 (2017) 697–709 Weinheber, Peter, et al., 2006. New formation tester probe design for low-contamination sampling. In: SPWLA 47th Annual Logging Symposium. SPWLA 2006-Q. Weinheber, Peter, et al., 2009. Focus Sampling and Downhole Fluid Analysis - a West Africa Perspective. OTC 20024. Zazovsky, Alexander, 2008. Monitoring and Prediction of Cleanup Production During Sampling. SPE 112409. Zuo, Julian Y., 2008. Equation-of-state-based downhole fluid characterization. In: SPE Asia Pacific Oil and Gas Conference. SPE 114702-PA.
Nutt, R.L., et al., 1989. Time-lapse saturation monitoring and its applications to timelapse mapping. In: SPE Middle East Oil Technical Conference and Exhibition. SPE 17975-MS. Qi, Hu, et al., 1999. Estimation of true formation resistivity and water saturation with a time-lapse induction logging method. Log Analyst 40 (2). SPWLA Journal Paper 1999-V40N2A1. Singha, Kamini, et al., 2012. Monitoring tracers with time-lapse electrical methods: issues with reactions and surface conductance. In: SEG Las Vegas 2012 Annual Meeting. SEG Conference Paper 2012-1345.
709
Contents lists available at ScienceDirect
Journal of Petroleum Science and Engineering journal homepage: www.elsevier.com/locate/petrol
A novel formation tester for high quality virgin formation fluids sampling and its arrival prediction under deep invasion Peihu Wang, Lizhi Xiao * State Key Laboratory of Petroleum Resources and Prospecting, China University of Petroleum, Beijing 102249, China
A R T I C L E I N F O
A B S T R A C T
Keywords: Downhole fluids sampling and invasion Time elapse formation resistivity Deep invasion Virgin fluids type detection and prediction
In the past few years, many studies have been focused on how to take virgin formation fluids successfully under increasingly tough formation conditions, such as:
Low permeability zones: Based on field test feedback, traditional probe has difficulty taking formation fluids sample when permeability is less than 1md. By re-designing the probe to increase its surface contact area with the formation; flowrate can be increased significantly which helps in taking formation fluids' samples. It is reported from field that the latest Saturn 3D Radial probe successfully took samples in 0.01md permeability formation because its probe area is around 500 times that of a standard traditional probe. Drilling with oil based mud: Due to oil based mud filtrate mixing with formation oil, it is difficult to take a clean virgin formation fluid sample. For this challenge, the researcher designed a special probe splitting traditional probe's flowline from single flow line into two separate flow lines; a guard line and a sample line to separately draw mud filtrate and virgin formation fluids. Virgin formation fluids collection is totally dependent on the ability to draw the fluid into the probe. Besides low permeability and fluids mixing, deep invasion is another challenge that can hinder the drawing of a clean virgin formation fluid sample. According to experiments and practice in the field, whether virgin formation fluids can be taken successfully depends mainly on the formation permeability. In theory, the higher the permeability, the easier it is to draw formation fluids into formation tester. However, with increasing invasion depths, mud filtrate occupies a bigger area surrounding the borehole and will lead to difficulty for virgin formation fluids breaking through and flowing into formation tester probe. This is because a large amount of mud filtrate will flow into the probe along different orientations. According to this research paper, in order to speed up the formation oil flow into the probe, the permeability heterogeneity plays a very important role. The numeric simulation shows that if formation permeability is more heterogeneous, the virgin formation fluids can be easier to obtain because horizontally oriented fluids will form a dominant flow channel which has a relatively higher velocity compared to the vertically oriented fluids. So, the traditional sampling method becomes increasingly difficult to take virgin formation fluids sample in both low permeability zones and high permeability homogenous zones. To solve the problems facing the ease of pumping virgin formation fluids into the probe, this paper will demonstrate a novel tool design combining traditional formation testing tools and resistivity tools to measure the formation resistivity of virgin fluids sweeping area in real time. By adding electric buttons on the Saturn probe and measuring its voltage trend during pumping, we can obtain 4 different orientations' formation resistivity trends in real time. Through inversion of the formation resistivity of sweeping area nearby borehole, we can estimate virgin formation fluids properties in real time and predict when virgin formation fluids flow into the probe.
* Corresponding author. E-mail addresses: [email protected] (P. Wang), [email protected] (L. Xiao). http://dx.doi.org/10.1016/j.petrol.2017.06.029 Received 12 September 2016; Received in revised form 5 December 2016; Accepted 14 June 2017 Available online 17 June 2017 0920-4105/© 2017 Elsevier B.V. All rights reserved.
P. Wang, L. Xiao
Journal of Petroleum Science and Engineering 156 (2017) 697–709
Darcy law (Kyi et al., 2015), the fluids' flow rate can be expressed as below: In Fig. 1, we know the flow rate (q) has linear relationship with formation property and probe properties. Under particular pressure difference and formation property, more fluids can be drawn with a bigger probe Area (A). This was the focus of most recent research in that area. According to Fig. 2, the latest Saturn 3D radial probe area is around 500 times (Daungkaew et al., 2014; Cig et al., 2014) that of a standard probe area. The Saturn 3D Radial probe was successfully deployed in the Field since 2014, and it was reported that fluids' samples were taken successfully in very low permeability zone (0.01md) (Cai et al., 2014). Compared with standard probe, the Saturn 3D radial probe significantly extends working zone from the lowest permeability 1md to 0.01md. Besides the low permeability application, faster sampling of virgin formation fluids is another main research topic. Due to mud filtrate invasion, traditional probes find it very difficult to take virgin formation fluids because a large volume of filtrate mixed with virgin formation fluid flow into the probe. So, the main benefit of focus probe design is to split traditional probe single flow line into two separate flow lines, a guard line and a sample line with separate flows (Kundu et al., 2007; Nagarajan et al., 2011; Weinheber et al., 2006) (see Fig. 3). Compared to traditional probe design, the guard flow line main focus is drawing mud filtrate and sample flow line only need to draw the fluids in front of it. In theory, the focus probe will be faster than traditional probe to obtain virgin formation fluids. Through analyzing fluids OD trend inside flow line of formation testing tool (Mullins et al., 2000; Zazovsky, 2008; Zuo, 2008; ; Weinheber et al., 2009) during pumping, contamination can be calculated in real time and then it can be predicted when it is good time to take sample.
Fig. 1. Darcy law with formation and probe properties (Probe Area).
1. Introduction 2. Challenges
Since the first generation formation testing tool was deployed into the Field, it was already successfully applied in taking fluids' samples for more than 60 years. In order to minimize potential stuck risks, operators prefer to take virgin formation fluids sample as fast as possible. According to formation testing tool probe design and
The operator needs conventional logs to help to pick up the optimum station to take sample. The well A of Iraq oil field was drilled using water based mud in 2014 (see Fig. 4). After conventional logs analysis, it was
Fig. 2. Surface area comparison in formation testing probe family.
698
P. Wang, L. Xiao
Journal of Petroleum Science and Engineering 156 (2017) 697–709
Fig. 3. Focus probe design and fluids flow path sketch.
Fig. 4. Formation test vs. conventional log plot. 699
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Journal of Petroleum Science and Engineering 156 (2017) 697–709
Fig. 5. Probe Resistivity curve vs. cumulative pump out volume cross plot in station SP-2.
same zone and fluid types should have been similar. We got an oil sample from the station SP-1, but a water sample from SP-2. After analysis, it was thought that invasion depth of SP-2 was deeper than that of station SP-1, which lead to the inability to draw virgin formation fluids from station SP-2 within an appropriate time frame. Based on this real scenario, it was identified that the biggest challenge was the virgin formation fluids inability to be drawn into the probe under deep invasion conditions leading to the inability to estimate virgin fluids type due to sample failure. Besides the real field case, this paper uses numerical simulator (Eclipse) to demonstrate why virgin formation fluids can't be drawn into the probe under deep invasion conditions. Fig. 7 is simulation formation model. Compared with other probes, Saturn 3D Radial probe is faster to obtain virgin formation fluids because it has a bigger surface area. For this simulation, we use this 3D probe with the formation parameters
identified that two stations SP-1 and SP-2 were located in the same zone and with similar fluid properties. The operator decided to take samples from these two stations. After 5 consecutive hours of pumping, an oil sample was successfully taken from station SP-1 which is consistent with conventional logs. While sampling from station SP-2, we couldn't get an oil sample even though 100 L of fluid were pumped out in 6 h. Fig. 5 shows the fluid resistivity only change a little bit and its value is less than 1.0 Ω m until pump stop. It is typical characterization of water. Based on Fig. 6, we found the water channel signal is very high, color channel and oil channel stays constantly lower during the pumping, which indicates that the fluid in the formation tester flow line is water as well. Analyzing probe resistivity and OD trend, it could be concluded that the fluid inside formation tester is water. But from conventional logs' analysis, we knew that the stations SP-2 and SP-1 were located in the
Fig. 6. OD trend with continuous pump volume cross plot in station SP-2. 700
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Journal of Petroleum Science and Engineering 156 (2017) 697–709
orientation formation resistivity. As Fig. 12, the main current (in the middle) will penetrate in the formation as annular electronic beam because there are four focus electrodes surrounding it and emitting focus current to form current shielding layer avoiding main current divergence (see Figs. 11 and 13). 3.2. Measurement principle There are four monitoring electrodes were deployed surrounding the main current to measure voltage. With pumping out time elapsing, the voltage of the four measurement electrodes will change with radial saturation change. From Fig.14, the formation resistivity changes with pump out time elapse. If the zone bears oil, the formation resistivity will increase; otherwise, the formation resistivity will decrease accordingly when formation water has higher salinity than water based mud filtrate (see Fig.15). Fig. 7. Formation model.
3.3. Experiment analysis
shown in Table 1. According to Saturn 3D Radial probe design in Fig. 2, Saturn 3D Radial probe includes 4 probes in different orientations which allow it to separately draw formation fluids from 4 orientations (see Fig. 10). Fig. 8 shows oil saturation distribution when probe draw fluids with constant flow rate 20 cc/s within 6 h. We know the virgin fluids can be drawn into the probe only when horizontal permeability reaches 50 md and vertical permeability was kept as 1md. However, with vertical permeability increase, the virgin formation fluids can't be drawn into probe as well. From Fig. 9, it is shown that permeability heterogeneity plays an important role which directly affect whether virgin formation fluids can be drawn into probe successfully or not. Based on the above simulation results, the deep invasion is the biggest challenge. The reason is that the more homogenous formation is would be lead to a different orientation fluids flowing together into probe so that the fluids in the front of probe can't form a dominant channel to flow into the probe in the limited pumping out time.
Two kinds of sandstone cores were picked up to do oil driven water experiments in the Lab to verify whether numerical simulation results above were reliable or not. The experiment takes traditional single pore system core. The experiment shows core resistance increasing continuously with time elapsed of oil driven water (see Fig.16). For dual porosity system, the core resistance response is same as single porosity system (see Fig.17). Based on the core experiments above, no matter what kind of porosity system, core resistance had consistent response with numerical simulation results. 3.4. Inversion According to ohm's law, the electric field strength is related to electric density and formation resistivity.
E ¼ R⋅J
3. Solution
(1)
The new tool discussed in this paper takes lateral focus emitted current, there are four focus currents forcing main current to penetrate into the formation in a horizontal cylinder shape. Based on this tool's design, the electric density will equal to
Virgin formation fluids can't be drawn into the probe under deep invasion conditions within limited pump out time; this paper will focus on designing a novel tool to estimate fluids' properties by measuring formation resistivity rather than directly measuring fluids' resistivity and then predict when virgin fluids can flow into probe.
J¼
Io 2πhr
(2)
where: 3.1. New tool design Io Main current h The current thickness r The main current distribution radius
According to Saturn 3D Radial probe design, this new tool will be designed to have an ability to measure four orientated formation resistivity. The resistivity measurement takes lateral log principle to measure formation resistivity. The main current will be adjusted by four focus current and it can directly flow into formation. The four measuring electrodes will measure voltage and they are used to calculate different
Because
E¼
du ¼
Table 1 Formation parameters in the simulator. Formation Property
Horizontal(md)
Vertical(md)
Permeability
10 20 50 2 m*2 m*2 m 15%
1 1 1
U
Volume Porosity
du dr
(3)
Io R dr 2πh r U
(4)
U
∫ Umo du þ ∫ Uxom du þ ∫ Utxo du ¼
701
Io Rm rc dr Io Rxo ri dr þ ∫ ∫ 2πh ro r 2πh rc r Io Rt rt dr þ ∫ 2πh ri r
(5)
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Journal of Petroleum Science and Engineering 156 (2017) 697–709
Fig. 8. Formation model mesh and oil saturation distribution after pumping 6 h.
Fig. 9. Oil saturation distribution under different permeability formation.
Io Rm rc Io Rxo ri Io Rt rt ln þ ln þ ln Uo Ut ¼ 2πh ro 2πh rc 2πh ri
as below:
Kd rc Kd ri Kd rt ln ln ln Rm þ Rxo þ Rt 2πh ro 2πh rc 2πh ri
(6) Ra ¼
where:
(8)
Uo : The voltage on the tool face Ut : The voltage of the uninvaded formation ro : Tool radius rc : Well bore radius ri : Invasion radius rt : Uninvaded radius
From equation (8), we know the apparent resistivity is the summation of each formation component resistivity in any particular time (Moinfar et al., 2010; Dalton et al., 2002; Qi et al., 1999; Singha et al., 2012; Charara et al., 2001; Nutt et al., 1989; Gomes et al., 1999; Li and Chen, 2003; Morriss et al., 1996; Mitchell et al., 2010). So, we can reduce equation (8) as to:
Lateral log resistivity can be expressed as below:
Rj ¼
Ra ¼ Kd
ðUo Ut Þ ΔUd ¼ Kd Io Io
(7)
n Kdj X ri Ri *ln 2πh i¼1 ri1
(9)
where:
where:
Rj : The tool measured resistivity of the horizontal resolution j along the radius Kdj : The tool factor of resolution j Ri : The formation resistivity of component i ri : The radius from component i to tool
Kd : Tool electric factor Ra : Apparent resistivity Merging equations (6) and (7), the resistivity can be re-written
Fig. 10. Traditional Saturn 3D Radial probe. 702
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Journal of Petroleum Science and Engineering 156 (2017) 697–709
where: Rw : The formation water resistivity Swi : The saturation of the formation component i During the pumping out period, fluids flow model is spherical flow and the oil flow rate is equal to
vr ¼
Ko dp Ko Pw Pe 1 ¼ μo dr μo 1 1 r 2 Rw Re
(11)
where. Pw : Probe pressure Pe : Formation pressure Rw : Well bore radius Re : Reservoir radius In the given time, the fluids flow distance is equal to:
dr ¼ vr dt
As Fig. 18 described and core experiment, the radial water saturation can be expressed as below:
Fig. 11. Resistivity measurement mounted on the each side of 3D Probe.
8 > > Sw ¼ 1 Sor > > > <
Based Saturn 3D Radial probe fluid suction principle, the formation resistivity changes with radial saturation change because the virgin formation fluids will replace the filtrate invasion area with time elapsing (Huang, 2011; Chassange et al., 2012). For resistivity in each component, it can be expressed by Archie's equation:
Ri ¼
abRw ∅m *Snwi
(12)
Sw ¼ 1 ð1 Swb Þ*e > > > > > : Sw ¼ Swi
r
¼ 1 ð1 Swb Þ*e
ðPw Pe Þ μo 1 1 Rw Re
ð
Þ
Δt r2
ri < r < rt
(13)
r >rt
So, the invasion target is how to calculate ri during the pumping out and predict when the virgin fluids can flow into probe.
(10)
Fig. 12. Main current and focus current contour plot. 703
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Journal of Petroleum Science and Engineering 156 (2017) 697–709
Fig. 13. Current and voltage contour plot.
major purposes were to get samples and predict oil production. In order to achieve these two objectives, the LWD resistivity tool and sampling tools were used. In Fig. 21, the blue curve, including GR and Resistivity track, comes from drilling path. The red curve comes from ream pass. Before sampling, the ream pass GR was measured to locate target zone. Due to the well was drilled by water based mud, the ream pass resistivity is a little bit lower than drilling pass due to water based mud filtrate invasion. In order to get clean oil samples in station 3, there are 30 L fluids pumped out in 3 h. Figs. 22 and 23 show both water based mud filtrate and formation oil are pumped into formation tester tool together. In order to compute oil production more accurate, the fluids mobility need to calculate accurate as well. So, another station 15 was performed below the station 3 but its main purpose is just to obtain drawdown mobility by pretest mode. The green curve in resistivity track shows formation resistivity on
3.5. The synthetic simulation data inversion case analysis During pumping out, the four sink probes will draw formation fluids simultaneously. According to the seepage principle, the fluids flow shape will show spherical in each probe area (see Fig. 19). As Fig. 20 describe, the formation response area will be linear with the distance between negative electrode and focus current electrode. The further the distance between the two electrodes, the deeper of formation component will contribute more to the signals. Apply Tables 2 and 3 parameters into equation (14), we get the invasion depth is 0.2504 m which is very close to model value 0.25 m. 4. Case study for real time formation resistivity response validation in sampling job The appraisal well B was drilled in the x oilfield in 2016. The two
Fig. 14. Measure electrode voltage vs. Elapse pumping out time on oil zone. 704
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Journal of Petroleum Science and Engineering 156 (2017) 697–709
Fig. 15. Measure electrode voltage vs. Elapse pumping out time on water zone.
Fig. 16. Core resistance response with oil driven water under single pore system.
Fig. 17. Core resistance response with oil driven water under dual porosity system. 705
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Journal of Petroleum Science and Engineering 156 (2017) 697–709
Fig. 18. Saturation distribution along well radius.
Fig. 19. Saturn 3D Radial probe spherical flow model.
5. Conclusion
station 15, which is measured by new ream up pass. Comparison with station 3, we found the P34H resistivity curve of station 15 has significantly increasing, which shows the virgin formation oil is drawn into invasion zone to replace part of water based mud filtrate and this is root cause of P34H resistivity measurement increasing. This case shows the time lapse resistivity measurement can help to identify virgin formation fluid type during pumping (see Fig. 24).
● According to simulation results, it was found that formation testing tools can't take virgin formation fluids sample when pumping out time is less than 6 h and if invasion depth is larger than 0.85 m. So, the deep invasion is the biggest challenge for fluids' sampling. ● Through re-designing formation testing tool by applying real-time formation resistivity measurement, we can obtain formation fluids properties in real time and it can help to make decision whether it is needed to continue pumping out to wait for virgin fluids arrival. With real-time formation resistivity help, even no virgin formation fluids flow into probe, data interpreter still can estimate virgin formation fluids type, like oil or water. Compared with traditional formation testing tools, the new tool can mitigate data interpretation uncertainty and improve interpretation accuracy. ● Through real-time measurement of formation resistivity, we can compute invasion depth in real time. By computing invasion depth movement velocity, we can predict how long time is needed to consume when virgin formation fluids flow into probe, which will be
Table 2 Forward modeling parameters table.
Fig. 20. Saturn 3D Radial probe resistivity measurement principle. 706
Formation Component
Resistivity(ohm m)
Radial Depth Interval (m)
Invasion Zone Transition Zone 1 Transition Zone 2 Virgin Zone
1.67 2.5 5 50
0.1–0.25 0.25–0.75 0.75–0.9 0.9~
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Journal of Petroleum Science and Engineering 156 (2017) 697–709
Table 3 Tool Design parameter table & Simulation Data.
Rj ¼
Kdj rd Kd j ri1 Kdj ri2 Kdj rd Kd j ri1 Kdj ri2 ln ln ln ln ln ln Rinvasion þ Rxo1 þ Rxo2 þ 1 Rt 2πh rd 2πh rc 2πh ri1 2πh rc 2πh rd 2πh ri1
(14)
The distance between negative and focus electrode
The voltage of measurement electrode
Tool Factor
The main current(A)
The Apparent Resistivity(ohm.m)
1.25 1.15 1.05 0.95
12.35 12.17 11.96 11.75
0.97 0.94 0.9 0.86
2 2 2 2
5.99 5.72 5.38 5.06
m m m m
V V V V
Fig. 21. Combine LWD resistivity and Sampling log view.
Fig. 22. OD trend with pumping elapse time.
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Journal of Petroleum Science and Engineering 156 (2017) 697–709
Fig. 23. Fluids fraction trend with pumping elapse time.
Fig. 24. Resistivity comparison between drilling pass and ream pass.
used to help operators optimize pump out velocity to mitigate tool stuck risk.
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