32 Oilfield Review

New Dimensions in Wireline Formation Testing

Operators have had difficulties obtaining pressure measurements and samples

with conventional wireline formation testers in certain formations and reservoir

fluid types. Engineers have recently developed a tool for reliable testing even in

challenging environments such as low-mobility formations and heavy oil.

Cosan Ayan Paris, France

Pierre-Yves CorreAbbeville, France

Mauro FirinuEni SpA E&PRavenna, Italy

Germán GarcíaMexico City, Mexico

Morten R. KristensenAbu Dhabi, UAE

Michael O’KeefeLondon, England

Thomas PfeifferStavanger, Norway

Chris TevisSugar Land, Texas, USA

Luigi Zappalorto Eni Norge SAStavanger, Norway

Murat ZeybekDhahran, Saudi Arabia

Oilfield Review Spring 2013: 25, no. 1. Copyright © 2013 Schlumberger.ECLIPSE, MDT, Quicksilver Probe and Saturn are marks of Schlumberger.

1. For more on WFTs: Ayan C, Hafez H, Hurst S, Kuchuk F, O’Callaghan A, Peffer J, Pop J and Zeybek M: “Characterizing Permeability with Formation Testers,” Oilfield Review 13, no. 3 (Autumn 2001): 2–23.

Spring 2013 3333

Engineers seeking to characterize reservoirs and design completions for maximum production effi-ciency depend heavily on analysis of downhole reservoir fluid samples and transient pressure testing. But identifying mobile fluids and defining hydrocarbon columns can be difficult in complex formations. Reservoir engineers and petrophysi-cists use a variety of data to make accurate reserves estimates and create representative res-ervoir models. These include fluid composition, pore pressure measurements, reservoir tempera-ture, reservoir response to pressure changes and integration of seismic data.

In the past, most formation fluid samples were captured after they reached the surface during drillstem tests and production well tests and were then separated into gas, oil and water

components. These samples were transported to offsite laboratories for analysis. Well tests con-tinue to provide engineers with useful data about reservoir fluids, reservoir size and produc-tion potential. But characterizing fluids from samples captured at the surface can be prob-lematic. Recombination of the separated fluids at the surface requires great care: It is often difficult for technicians to avoid contaminating the samples or inducing pressure losses during capture and transportation, particularly when working at remote locations; re-creating in situ conditions in the laboratory is difficult but nec-essary for accurate analysis.

In the 1950s, the industry began addressing these and other sampling difficulties by introduc-ing wireline formation testers (WFTs) that were

lowered on wireline logging cable to the zone of interest. One recent version of these tools uses dual straddle packers inflated above and below the sample point, or station, to isolate the forma-tion from wellbore fluids and to expose more of the formation for sampling (above left). Formation fluids are then flowed or pumped into the tool for capture and retrieval to the surface.

Probe-type WFTs use hydraulically operated arms to force a packer assembly against the borehole wall (above). The probe, located in the center of the packer, extends into the forma-tion, and then reservoir fluids flow or are pumped into the tool. The fluids are analyzed downhole, and samples may be captured while pressure is measured using downhole gauges. Fluids are analyzed for purity before being directed to the sample chambers. This allows contaminated fluids to be removed before wire-line engineers take formation samples. Sample bottles maintain the fluids at formation pres-sure to avoid phase changes while the samples are being retrieved to the surface for transport to a laboratory for analysis.1

> Dual straddle packer wireline formation tester (WFT). Some WFTs use hydraulic inflatable packers to seal the formation from contamination by borehole fluids during sampling and transient testing.

Borehole fluid

Fluid intakeopening for WFT

Inflatable packer

Inflatable packer

Borehole fluid

> Probe-type WFT. Once a probe-type tool is on depth, the tool extends pistons from one side of the WFT against the wellbore wall, while a packer assembly is forced firmly against the formation to be tested. A probe in the center of the packer assembly then extends into the formation; the reservoir fluids flow through the probe into the tool’s flowline and sample chambers for retrieval to the surface. The packer seal, which surrounds the probe, prevents wellbore fluids from mixing with reservoir fluids.

Packer assembly

Probe

Pistons

34 Oilfield Review

Cont

amin

atio

n le

vel

Time

Acceptable sample

Sample intake

Seal Seal

Contaminatedintake

Guardintake

Flow tube tosample chambers

Flow tube towellbore

WFTs often delivered fluid samples that were more representative of reservoir fluids than those captured on the surface. However, the probes used in early tools were not applicable in certain forma-tions where establishing a seal was difficult. In addi-tion, testing formations in which fluids move slowly to the tool prolonged the time the tool was on sta-tion and often resulted in samples that were con-taminated with excessive mud filtrate. Furthermore, highly viscous fluids can typically be mobilized through the formation and into the wellbore only by creating a relatively high differential pressure between the wellbore and the formation. This draw-down, or differential pressure, may exceed the rat-ings of the WFT packer or may cause the borehole wall in unconsolidated formations to fail, leading to loss of the seal around the packer assembly.2 A high pressure differential may also cause the pressure at the tool to drop below the bubblepoint pressure, inducing free gas and composition changes in the oil, which jeopardizes sample integrity.

In certain well conditions, it may be difficult to capture representative samples using standard single-probe WFTs because the sealing packer isolates the formation or the probe assembly only from drilling or completion fluids in the borehole. Fluids that have invaded permeable zones may also contaminate the sample. To acquire a rela-tively pure sample of reservoir fluids, engineers use a pumpout module—a miniature pump

included in the WFT toolstring—to flow or pump fluids from the formation through the tool and out to the wellbore until contaminants have been pumped away. The nature of the incoming fluids is analyzed downhole by a variety of sensors. Flow is then directed to sample bottles that capture and store fluids for transport to surface laborato-ries for analyses.

Under any condition, obtaining a representa-tive reservoir fluid sample can be a challenge because it can be difficult for engineers to know when the flow stream is sufficiently purged of contaminants. Engineers must rely on informa-tion about the reservoir and nature and amount of contaminant invasion to calculate the time it will take for the formation to clean up at a given flow rate. This calculation is further complicated because the flow from the reservoir streams in a conical volume toward the probe and draws con-taminants from the near-wellbore invasion zone as well as from some vertical distance along the wellbore. The outer edge of this flow stream may contain significant nonreservoir fluids, which may then require extended periods of time to be pumped away. Often, because engineers may underestimate the amount of time this process can take, they capture nonrepresentative sam-ples, or conversely, if engineers overestimate the time, they spend unnecessarily long and costly periods of time at the sampling station.

Innovations in WFT designs have done much to overcome these limitations. For instance, to shorten cleanup and ensure a representative sample, Schlumberger engineers developed the Quicksilver Probe focused extraction of pure res-ervoir fluid tester, which uses two concentric

sampling areas through which pumped fluids enter the tool. The outer ring is a conduit for the more contaminated outer segment of the flow stream, which is discarded to the wellbore. The inner probe draws fluids from the more represen-tative inner section of the conical flow, which may then be diverted into the WFT sample bot-tles (below).3

Another innovation, downhole fluid analysis (DFA), uses optical spectroscopy to identify the composition of reservoir fluid as it flows through the WFT. This technology allows engineers to determine contaminant levels and begin sam-pling only after these levels within the flow stream have reached an acceptably low value. When DFA is deployed at selected intervals within a well and in multiple wells, engineers gain previously unavailable data with which to perform reservoir architecture analysis.4

In addition to ensuring the purity of samples, these innovations shorten time on station, which may aggregate to significant savings in operating expenses. However, hurdles remain. This article discusses obstacles to capturing fluid samples in certain troublesome reservoirs and a new WFT probe that helps overcome these obstacles. Case histories from the Middle East, Mexico and Norway illustrate how the new tool facilitates fluid sampling in challenging environments.

The Continuing ChallengesIn most formation types, enhancements to WFT technology have greatly increased an operator’s ability to capture representative fluid samples suit-able for analysis while obtaining highly accurate downhole pressures. But operational constraints, unconsolidated sands, heavy oils and low-permea-bility rock still impact sampling success.

Traditional dual straddle packers offer one solution for these conditions. However, this solu-tion comes with operational concerns. In large holes, the packers require extended inflation times, and their relative positioning above and below the zone being tested creates a large sump volume. The effect of this storage volume can sig-nificantly extend cleanup times and create prob-lems for transient testing measurements in low-permeability reservoirs.5

In the testing of low-mobility formations, draw-down pressures during pumpout may become quite high. The resulting differential pressures can exceed existing straddle packer ratings of about 31 MPa [4,500 psi]. High differential pressures may also result from flowing high-viscosity fluid through unconsolidated sands, causing seal failure or even borehole wall collapse.

> Formation fluid sampling with the Quicksilver Probe focused sampling tool. The probe has two intake ports, the guard intake surrounding the sample intake (bottom left). Packers surround and separate these probes and seal against the borehole wall (right). Formation fluid is blue-gray and filtrate is light brown. When pumping begins, fluid flowing through the sample intake is highly contaminated (top left), but contamination levels quickly reach an acceptable value.

Spring 2013 35

Crumbling formations may also foil sampling operations when sand from the formation plugs the probe and flowlines. In addition, drilling through rock with low mechanical strength typi-cally results in a highly rugose wellbore wall with few sections of in-gauge hole against which to obtain a good packer seal.

To address these issues, engineers have increased probe size 10-fold over the years and devised probe shapes to better accommodate various formation types. Probes that create larger flow areas have increased success rates in tight formations and friable sands, and dual packer technology has increased the ratings for differential pressure to 40 MPa [5,800 psi]. DFA measurements also help ensure sample purity and enable a different set of complex fluid anal-yses than is possible on samples brought to the surface and transported to laboratories. The next step in the evolution of WFTs was recently introduced by engineers at Schlumberger with the development of a probe that provides a sig-nificantly larger flow area between the forma-tion and the tool while simultaneously providing a better sealing element.

A Radial Solution To address the limitations of differential pressure and issues of related seal and packer failures, Schlumberger engineers developed the Saturn 3D radial probe. This tool uses four elongated ports spaced evenly around the circumference of the module rather than a single probe or dual packers. The ports are individually isolated from the wellbore by a single inflatable packer that creates a large sealing surface against the forma-tion (right).

The packer used in the Saturn probe seals more reliably against a rugose borehole than sin-gle-probe WFT packers do and inflates and deflates more quickly than the dual straddle packers while completely eliminating sump volume. The four openings are embedded in the packer, and each is significantly larger than those on conventional probes, which further hastens cleanup.

Cleanup time—a primary component of for-mation test times—is the period required to flow the well until contamination of the reser-voir fluid flow stream has been eliminated or reduced to an acceptable level. One key to reducing prolonged test times is to shorten cleanup through higher flow rates. To test whether the Saturn probe design accomplishes this goal, reservoir engineers constructed a numerical model comparing cleanup time using the Saturn probe to those with a traditional

2. Drawdown is a differential pressure condition that induces fluids to flow from a reservoir formation into a wellbore. It occurs when the wellbore pressure is less than the formation pressure and may occur naturally or be created by pumping or producing from the well.

3. For more on the Quicksilver Probe tool: Akkurt R, Bowcock M, Davies J, Del Campo C, Hill B, Joshi S, Kundu D, Kumar S, O’Keefe M, Samir M, Tarvin J, Weinheber P, Williams S and Zeybek M: “Focusing on Downhole Fluid Sampling and Analysis,” Oilfield Review 18, no. 4 (Winter 2006/2007): 4–19.

> Saturn probe. The Saturn probe (top) captures reservoir fluid samples through four large ports spaced evenly on the tool’s circumference. The ports are pressed against the borehole when the packer that contains them is inflated, which creates a seal separating reservoir fluids from wellbore fluids. The tool geometry provides a radial flow pattern (middle, right) for reservoir fluids (green) and faster removal of contaminated fluids (blue). This differs from the flow pattern of a typical WFT (middle, left), which has a single opening on one side of the tool. The Saturn probe also has a flow area that is many times larger than that of traditional probes (bottom).

Fluid intakeports

Inflatablepacker

79.44Surface flow

area, in.2

6.03Surface flow

area, in.2

The Saturn 3D radial probe, which uses four ports, increases theprobe surface area to more than 500 times that of the standard probe.

2.01Surface flow

area, in.2

1.01Surface flow

area, in.2

0.85Surface flow

area, in.2

0.15Surface flow

area, in.2

Saturn 3DRadial Probe

EllipticalProbe

Extra LargeDiameter Probe

Quicksilver ProbeProbe

Large DiameterProbe

StandardProbe

4. For more on downhole fluid analysis: Creek J, Cribbs M, Dong C, Mullins OC, Elshahawi H, Hegeman P, O’Keefe M, Peters K and Zuo JY: “Downhole Fluids Laboratory,” Oilfield Review 21, no. 4 (Winter 2009/2010): 38–54.

5. Wellbore fluid expansion and compression effects distort the reservoir response to pressure changes used in pressure transient analysis. A critical element of pressure transient analysis is distinguishing between the wellbore storage effects and the true reservoir pressure response.

36 Oilfield Review

extra large diameter (XLD) probe. The team used ECLIPSE reservoir simulation software on three probe configurations to test the proposi-tion. A fine grid was used to model the XLD and Saturn probes. For miscible contamination, investigators simulated a single-phase fluid sys-tem and represented the drilling fluid filtrate contamination using an embedded tracer. In addition, investigators conducted immiscible modeling for oil-wet and water-wet systems.

During the simulated tests, engineers consid-ered parameters such as permeability, anisotropy, viscosity contrast between filtrate and oil, disper-sion of the invasion front and extent of invasion. In a miscible contamination cleanup scenario, engineers found that although the breakthrough of formation oil is faster for the XLD probe, cleaner samples can be collected with the Saturn

3D radial module with less total volume pumped. In a simulation of immiscible contamination cleanup, mud filtrate viscosities of 1.0 cP [1.0 mPa.s] and 0.6 cP [0.6 mPa.s] were used. In scenarios using typical water- and oil-wet relative permeability, cleanup times to reach 5% contami-nation were similar to those for miscible contam-ination (above).6

Because mobilizing heavy fluids often gener-ates drawdown pressures high enough to cause weak formations to collapse, the combination of high-viscosity fluids in poorly consolidated sands constitutes one of the most formidable wireline formation testing challenges.

The behavior of fluid flow from the reservoir to the sampling tool is governed by Darcy’s law, in which flow is directly proportional to perme-ability, drawdown pressure and cross-sectional

surface area and inversely proportional to fluid viscosity and the length over which the draw-down is applied. By introducing a flow area about 40 times larger than that of traditional XLD probes, the Saturn probe reduces the nec-essary drawdown pressure to mobilize heavy fluids or fluids in low-permeability formations (next page, top).

In the past, traditional WFT options restricted operators to a choice between the higher draw-down and reduced flow rate of a traditional probe and the larger flow rate of a straddle packer. The disadvantage of lower flow rates is longer cleanup times. On the other hand, while dual packers allow higher flow rates than the flow rates of tra-ditional probes, they create large storage vol-umes and may lose seal because they cannot provide necessary borehole wall support in unconsolidated formations. The Saturn probe design provides the benefit of both a probe and a dual packer: a large flow area to reduce time to cleanup and a packer-probe configuration that provides mechanical support of borehole walls to create a more reliable seal.

The Saturn 3D radial probe innovations allow operators to capture samples, perform DFA and identify transient flow regimes in situations where they previously could not. These include low-per-meability formations, heavy oils, unconsolidated formations, single-phase fluids close to the bubble-point, ultratight formations and others.7

Putting Theory to the TestAn operator deployed the Saturn tool to distin-guish between oil and water zones in formations that had been difficult to test using traditional tools. Among the problems was a history of forma-tion tests in which mud losses had restricted sampling time to four hours per station. Because these were also low-mobility formations, this operational constraint made it difficult to cap-ture samples using traditional probes.

Engineers viewed this operation as an oppor-tunity to compare the Saturn tool with traditional sampling methods. They designed a WFT tool-string that comprised an XLD probe, a Saturn probe, a compositional DFA module and several sample bottles. Engineers took multiple pressure measurements as the tool was run into the hole,

6. Al-Otaibi SH, Bradford CM, Zeybek M, Corre P-Y, Slapal M, Ayan C and Kristensen M: “Oil-Water Delineation with a New Formation Tester Module,” paper SPE 159641, presented at the SPE Annual Technical Conference and Exhibition, San Antonio, Texas, USA, October 8–10, 2012.

7. Mobility is the ratio of formation permeability to fluid viscosity. Therefore, lower formation permeability or higher fluid viscosity decreases mobility.

> Parameters of a cleanup test simulation. Engineers performed a model comparison of the cleanup efficiency of the Saturn probe, dual straddle packer and XLD probes using a reservoir model based on specific wellbore, formation, fluid and simulation parameters (top). Model output (bottom) confirmed that the greater flow area of the Saturn probe significantly decreased cleanup times for various vertical and horizontal permeabilities for both water-wet and oil-wet sands. The simulations take into account the storage effects of the dual packer sump. In these simulations, a sump volume of 17.0 L [4.5 galUS] is assumed, and oil- and water-base mud filtrates are assumed to be segregated instantaneously within the sump. The interval height between packers is 1.02 m [40 in.].

PorosityHorizontal permeabilityVertical permeabilityWellbore diameterFormation thicknessTool distance from boundaryFormation pressureMaximum drawdown during cleanupMaximum pumpout rateDepth of filtrate invasion

20%10 mD2 mD

21.6 cm [8.5 in.]50 m [164 ft]25 m [82 ft]

21 MPa [3,000 psi]4 MPa [600 psi]

25 cm3/s [0.4 galUS/min]10 cm [4 in.]

Common Parameters Value

Oil viscosityOil-base mud filtrate viscosity

1 cP1 cP

Oil viscosityWater-base mud filtrate viscosity

1 cP0.6 cP

Relative permeabilityResidual oil saturationIrreducible water saturationWater relative permeabilityOil relative permeabilityWater and oil core exponentsConnate water saturation

Water-wet0.100.200.201.00

3.0 and 1.50.12

Oil-wet0.300.150.800.60

1.5 and 3.00.12

Model Output

Model Output

Value

Saturn 3D radial probeXLD probeSaturn speedup over XLD probe

0.71 h9.10 h12.8

0.42 h7.17 h17.0

0.99 h14.61 h

14.8

MiscibleCleanup

Immiscible Cleanup,Water-Wet

ImmiscibleCleanup, Oil-Wet

Miscible Cleanup Parameters Value

Spring 2013 37

and seven samples were captured as the tool-string was retrieved from the well.

At the first station, samples were captured using the XLD probe after DFA measurements had identified 60% to 70% oil in the flow stream. The operator chose Station 2 in an effort to deter-mine the depth of lowest mobile oil. Engineers attempted to capture a sample at Station 2 using the XLD probe, but with a 13.8-MPa [2,000-psi] drawdown, a flow rate of only 5.2 L/h [1.4 galUS/h] could be achieved. After 1.5 hours of pumping, flow was switched to the Saturn probe, and although the flow rate was increased to 7.8 L/h [2.1 galUS/h], the accompanying drawdown was only 4.7 MPa [680 psi]. Under these conditions, flow stability was achieved and engineers were able to identify the oil/water delineation within the previously imposed four-hour time limit.

While sampling at Station 2 with the XLD probe, engineers observed no oil flowing in the first 34 L [9.0 galUS] pumped during cleanup (below). Even accounting for the XLD probe contribution, engi-neers concluded that oil arrived at the tool faster

> Three-dimensional contamination distribution. Models of cleanup using the Saturn probe and an XLD probe are shown at four points in time. The same drawdown is applied to both the XLD and the Saturn probes, but because of its larger flow area and multiple, circumferentially spaced drains, the Saturn probe can operate at higher pump rates and consequently achieve cleanup 12 to 18 times faster than the XLD probe. (Adapted from Al-Otaibi et al, reference 6.)

Satu

rn P

robe

Time 1 Time 2 Time 3 Time 4

XLD

Pro

be

Contamination

0 0.2 0.4 0.6 0.8 1.0

Contamination

0 0.2 0.4 0.6 0.8 1.0

Contamination

0 0.2 0.4 0.6 0.8 1.0

Contamination

0 0.2 0.4 0.6 0.8 1.0

Contamination

0 0.2 0.4 0.6 0.8 1.0

Contamination

0 0.2 0.4 0.6 0.8 1.0

Contamination

0 0.2 0.4 0.6 0.8 1.0

Contamination

0 0.2 0.4 0.6 0.8 1.0

> Finding oil. Logs of formation pressure (Track 1), mobility (Track 2), density-neutron-sonic (Track 3) and resistivity (Track 4) in this Middle East well would lead analysts to assume the target formation to be devoid of oil. However, DFA (Track 5) during pumpout indicated the presence of oil in the carbonate formation.

0.367 psi/ft (oil)

Formation Pressure

PretestMobilitymD/cP

Fluid Type

Lithology

MDTStation

psi 930 1,000530Photoelectric Factor

0.01

46

48

49

50

51

52

70%water

30%oil

40%water

waterStation 2

Station 1

Station 3

60%oil

0.477 psi/ft (water)± 0.021 psi/ft

Invaded Zone Resistivityohm.m

Bulk Density Correctiong/cm3

Formation Densityg/cm3

Thermal Neutron Porosity%

Delta-TSonic Porosity

% 10-in. Array Induction

ohm.m

20-in. Array Inductionohm.m

30-in. Array Inductionohm.m

60-in. Array Inductionohm.m

Resistivity

Sandstone

Porosity

Dolomite

Limestone

38 Oilfield Review

using the Saturn probe, which they attributed to the increased flow rate and radial cleanup.

The operator also tested a low-porosity, low-resistivity zone in the field. The first attempt, performed with an XLD probe, produced a 13.8-MPa drawdown and flow rate of less than 72 L/h [19.0 galUS/h]. Using the Saturn probe, engineers were able to reduce drawdown to 7.6 MPa [1,100 psi] with a flow rate of 288 L/h [76.1 galUS/h]. As a consequence, they were able to capture sufficient samples to delineate the oil/water contact (OWC) using the optical density mea-surements of the DFA module.

The Saturn probe was also used to identify a small amount of oil in a low-mobility zone in which pumpout was not possible with the stan-dard XLD probe. And finally, the operator sought to use sampling and DFA to determine the OWC in a heterogeneous carbonate formation with a resistivity measurement of 0.7 ohm.m. In this instance, in which traditional sampling tech-niques were unsuited to the task, engineers were able to use DFA measurements in conjunction with fluid samples captured with the Saturn tool to determine the thickness of the oil zone.8

Heavy Oil ChallengeHeavy oil is particularly problematic for conven-tional downhole sampling devices. Production of

this type of resource through proper placement of injection and production wells can be highly dependent on accurate fluid characterization. Because moving high-viscosity oil to the wellbore and then to the surface is often accomplished using steam injection and artificial lift, it is criti-cal for operators to be aware of higher-mobility zones within the reservoir layers created by rela-tively high-permeability rock or low-viscosity fluid. Both situations may create preferential high-mobility pathways through which the oil and steam flow and often result in significant bypassed reserves.

In 2011, the national oil company of Mexico, Petróleos Mexicanos (PEMEX), reported 60% of the nation’s oil reserves were heavy or extra heavy oil.9 As other more easily produced reserves are drained, these resources have become increasingly impor-tant to PEMEX and the nation. In the Samaria heavy-oil field in southern Mexico, PEMEX is trying to produce fluids with viscosities at downhole condi-tions as high as 5,000 cP [5,000 mPa.s] from forma-tions with unconfined compressive strength of from 0.69 to 5.5 MPa [100 to 800 psi].10 Because of chal-lenges presented by the combination of high-viscos-ity fluid moving through an unconsolidated formation, operators have been able to use WFTs to take pressure measurements in these formations but have been unable to capture samples. In the

Samaria field, PEMEX engineers have instead perfo-rated and flowed each zone individually and deployed sampling bottles on coiled tubing or a drillstring. Because this approach proved impractical and costly—often taking days or weeks per zone—the operator abandoned this sampling method.

As PEMEX engineers began a new develop-ment cycle in these Tertiary-age sandstones, they turned to the Saturn probe in 2011 to evaluate four wells. The primary team objective in the first well was to test the functionality of the new tool. In the second and third wells, engineers moved to full pressure testing with fluid scanning and sam-pling. In the fourth well, they also planned inter-val and vertical interference testing.

Multiple stations were tested and sampled in each of the wells. Because the formations are unconsolidated, the wellbores are often rugose and out of round—conditions that may cause a traditional probe to lose its seal before cleanup is

> Fluid sampling. The Saturn tool was used to acquire fluid samples and measure pressure (red) at the zone of interest. Initial measurements are mud pressure. At about 2,500 s, the tool is set and pumpout begins, followed by a buildup beginning at about 10,000 s, which establishes an estimate of reservoir pressure. Cumulative total volume pumped (green) begins to increase when the pump is turned back on at about 18,000 s to begin cleanup. At around 40,000 s, a second pump is engaged, which increases pump rate. The drawdown increases because of higher pump rate and the arrival of high-viscosity oil at the tool. Two spikes in pressure at about 55,000 s are the results of pressure shocks created when samples are captured followed by stopping the pump. Pressures are also recorded by an observation probe (black). Pumpout rates (tan and blue) are recorded on the far right axis in cm3/s for the first and second pumps, respectively. (Adapted from Flores de Dios et al, reference 10.)

Gaug

e pr

essu

re, p

si

Volu

me

pum

ped,

1,0

00 c

m3

2,000

1,800

1,600

1,400

1,200

1,000

800

600

400

200

0

10

0

10

40

20

30

20

30

40

50

60

70

80

90

100

110

Pum

pout

rate

, cm

3 /s

Elapsed time, s0 10,000 20,000 30,000 40,000 50,000 60,000 70,000

Saturn 3D radial probe pressure

Rate pump 2

Rate pump 1

Volume pumped

Quartz pressure gauge (observation) pressure

8. Al-Otaibi et al, reference 6. 9. Petróleos Mexicanos (PEMEX) Exploración y Producción:

“2011: Las reservas de hidrocarburos de México,” Mexico City: PEMEX (January 1, 2011): 22 (in Spanish).

10. Flores de Dios T, Aguilar MG, Perez Herrera R, Garcia G, Peyret E, Ramirez E, Arias A, Corre P-Y, Slapal M and Ayan C: “New Wireline Formation Tester Development Makes Sampling and Pressure Testing Possible in Extra-Heavy Oils in Mexico,” paper SPE 159868, presented at the SPE Annual Technical Conference and Exhibition, San Antonio, Texas, October 8–10, 2012.

11. Flores de Dios et al, reference 10.

Spring 2013 39

accomplished and samples captured. In the first well, tests were run with an XLD probe and a Saturn probe to test the sealing efficiency of the new system and to adjust variables such as set-ting and unsetting time, minimum inflation pres-sure for a seal and optimal pretest volume to account for storage effects.

The Saturn probe achieved 100% sealing in each of the seven stations tested using packer inflation pressures as low as 0.2 MPa [30 psi]. As a consequence, engineers were able to obtain full pressure surveys in both oil- and water-base mud environments that indicated only minor storage effects on the pressure responses. PEMEX engineers used the pressure surveys and mobilities determined from pretests to design completions that will evenly distribute injected steam in designated intervals, which will increase sweep efficiency.

As the testing for the Saturn tool continued, engineers captured minimally contaminated fluid samples from three wells using a toolstring that included an XLD probe and Saturn probes, fluid analyzers and sample bottles. Because of the unconsolidated nature of the formations, PEMEX engineers expected to use low differen-tial pressures that would require 16 to 20 hours per station to capture a sample; much of the time would be used to pump filtrate ahead of reservoir

fluids during cleanup. At the first station, while limiting differential pressure, engineers saw first hydrocarbon after 9 hours of pumping.

The pump speed was accelerated, and the dif-ferential pressure rose to about 200 psi [1.4 MPa]; no sand was seen in the tool. Flow pressure also decreased, indicating that the seal was holding. This led the team to abandon the original plan for low drawdown pressures and instead establish a 300-psi [2.1-MPa] differential minimum for Station 2 (previous page). The minimally con-taminated sample collected at this station was 7.5°API gravity oil; subsequent laboratory analy-sis documented that this sample had a viscosity of approximately 1,030 cP [1.03 Pa.s] at down-hole conditions and about 7,800 cP [7.8 Pa.s] at atmospheric conditions. Engineers will use the results from laboratory analysis of the samples in completion and production planning of the field.

In the fourth well, engineers performed inter-val pressure transient tests using the Saturn probe combined with an observation probe. These tran-sient tests consist of complete cleanup of the mud filtrate followed by variable-rate flow and shut-in periods, which are used to evaluate formation deliverability. Data from an observation probe higher on the toolstring provided engineers with information about formation permeability and

permeability anisotropy (above). PEMEX engi-neers are applying this information to calibrate cutoffs in nuclear magnetic resonance log pro-cessing, which they use to fine-tune permeabil-ity predictions.11

Low Mobility and High ConfidenceUsing resistivity log measurements, petrophysi-cists are able to delineate oil/water contacts in the majority of formations. However, in some for-mations, operators have difficulty interpreting the log response where water- and oil-bearing zones intersect. This uncertainty can affect how engineers choose to complete the well.

For one Middle East operator trying to deter-mine the extent of an oil zone in a tight carbon-ate formation, logs strongly indicated that the top of the zone was oil bearing and the bottom was water bearing. But log results for the middle zone were ambiguous; the resistivity response was similar to that of the water zone below it. Resolving the question of the fluid types of the middle zone with DFA measure-ments using traditional downhole sampling tools was precluded because establishing flow from the tight carbonate formation would have created a differential pressure greater than tra-ditional dual packer ratings.

>WFT interference test. The Saturn probe was run beneath a single-probe WFT. Engineers conducted an interval pressure transient test, obtaining vertical permeability (kv) and horizontal permeability (kh). Delta P and its derivative were recorded by the shallower observation tool (blue) and by the Saturn tool (green). Models were built using values of 12.2 m, 640 mD, 120 mD and 370 cP for height, kv, kh and viscosity, respectively. The modeled values (solid blue and green lines) reproduce the data closely, indicating that values for vertical and horizontal permeabilities are correct. (Adapted from Flores de Dios et al, reference 10.)

Delta

P a

nd d

eriv

ativ

e, p

si

Time since end of drawdown, s

10

101

101

102

103

102 10310

Modeled delta P, Saturn tool

Modeled derivative,Saturn tool

Modeled delta P,WFT observation probe

Modeled derivative,WFT observation probe

40 Oilfield Review

Using the Saturn probe, however, engineers were able to collect samples in all three zones, which confirmed light oil in the top zone and water in the lowest zone. After 15 hours of pumping at 4,900-psi [34-MPa] differential pressure from the 0.04-mD/cP mobility zone, DFA measurements indicated the presence of mobile light oil in the middle zone, which allowed the operator to deter-mine that the thickness of the oil zone was greater than initial estimates (above).

Drawdown RestrictionsIn some instances, operators have reason to use the Saturn 3D radial probe, even though a tradi-tional one might suffice. After engineers at Eni SpA saw the results achieved using the new probe in Ghana, engineers at an affiliated com-pany, Eni Norge, elected to try the service in the Goliath field in the Barents Sea. Engineers at Eni used this application to test sandstones in a relatively low-mobility environment, update the

> Low-mobility carbonate. Wireline log measurements (top) were inconclusive or provided conflicting interpretations in a formation in the Middle East. Porosity (Track 1) and resistivity (Track 2) measurements indicate an oil-bearing zone. However, log data from a middle zone were similar to those of the deeper water-bearing zone. Engineers resolved uncertainty in the middle zone by using the Saturn probe to capture a reservoir sample and a DFA module to measure fluid properties. Downhole fluid analysis (Track 3) indicated, similar to that in the top zone, the presence of oil in the middle zone. Flow from the tight carbonate formation required a differential pressure of 4,900 psi (bottom), which exceeds traditional WFT and packer ratings. (Adapted from Al-Otaibi et al, reference 6.)

Limestone

Lithology

Porosity

Dolomite

Pres

sure

, psi

Flow

rate

, cm

3 /s

Time, s

0500

0 10,000 20,000 30,000 40,000 50,000 60,000

1,0001,500

2,0002,500

3,0003,5004,000

4,5005,000

0

5

10

15

20

25

305,500

PressureRate

Photoelectric Factor

Invaded Zone Resistivityohm.m

Bulk Density Correctiong/cm3

Formation Densityg/cm3

Thermal Neutron Porosity%

Sonic Porosity

% 10-in. Array Induction

ohm.m

20-in. Array Inductionohm.m

30-in. Array Inductionohm.m

60-in. Array Inductionohm.m

Resistivity

Fluid TypeMDT

Station

Water

4,900-psipressure

differential

Sandstone

Clay

reservoir model and fluid contacts and increase their understanding of this new technology.

During the testing operations, the formation pressure survey encountered some supercharged low-mobility zones at the bottom of an oil col-umn. This introduced some uncertainty in the pressure gradient interpretation.12 Finding a clear delineation of the OWC also proved difficult because the resistivity log response could be attributed to either high water saturation or deep invasion effects. Fluid scanning with the Saturn probe identified the location of the OWC 5.5 m [18 ft] deeper than indicated by pressure gradi-ent and log response.

Furthermore, because of the large flow area of the Saturn probe, the strength of the lami-nated and low-permeability rock was confirmed. In this case, although reservoir mobility was a moderate 45 mD/cP, the reservoir pressure was near saturation pressure. Thus, a low drawdown pressure was essential to prevent a high pressure differential that might induce two-phase flow and an unrepresentative gas/oil ratio. Using the Saturn probe, a drawdown of only 0.5 bar [0.05 MPa or 7.3 psi] was needed to scan and clearly identify reservoir oil. A sample was also acquired using an XLD probe at another station in the same well in which the reservoir mobility was 880 mD/cP—more than an order of magni-tude greater than that of the reservoir sampled using the Saturn probe. Compared with the flow rate of the XLD probe, the Saturn probe achieved twice the flow rate at half the drawdown (next page). As a result, cleanup time was one-third of that using the XLD without raising concerns over the effects of extreme pressure changes on sample integrity.

Another Step ForwardThe industry’s ability to capture fluid samples and critical pressure data has evolved rapidly since the 1970s. Innovations in these arenas have been spurred by need to develop more-complex forma-tions with tighter limits on testing operations. With increasing frequency, engineers are testing weaker formations and producing high-viscosity fluids, which means tests must take less time at each station with lower drawdown ranges and lower flow rates. Often, these restrictions conspire to make sampling impossible.

12. Supercharging occurs when mud filtrate invading through the wellbore wall during drilling creates an overpressure in the formation around the wellbore. Pressure tests with WFTs, performed during the pretest, are affected by this overpressure, which is higher than the true formation pressure.

Spring 2013 41

> Drawdown and flow rate comparison. Engineers at Eni chose the Saturn probe to capture samples from a 45-mD/cP mobility reservoir and a single XLD probe to capture a sample in a much higher 880-mD/cP mobility reservoir within the same well. While flow rate (top, green line) through the Saturn probe (left) was nearly twice that of the XLD probe (right), the drawdown (blue line) was half that of the XLD probe. Fluorescence monitoring during cleanup (middle) indicated cleanup as fluorescence increased with fluid purity. The reservoir tested using the Saturn probe reached cleanup in 10 minutes (bottom left) compared with the XLD probe, which cleaned up in about 30 minutes (bottom right).

195.0

194.5

194.0

193.5

193.0

192.5

192.0

191.5

191.0

190.5

190.0

50

45

40

35

30

25

Pres

sure

, bar

Fluo

resc

ence

Elapsed time, min0

0

0.5

1.0

1.5

2.0

2.5

3.0

3.5

Elapsed time, minWater Mud-contaminated fluidOil

0 5 10 15 20 25 30 35 40 45 50

5 10 15 20 25 30 35 40 45 50

Flow

rate

, cm

3 /s

20

15

10

5

0

195.0

194.5

194.0

193.5

193.0

192.5

192.0

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190.0

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45

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30

25

Pres

sure

, bar

Fluo

resc

ence

Flui

d fra

ctio

n, %

Flui

d fra

ctio

n, %

Elapsed time, min0 10 20 30 40 50 60 70 80 90 100 110 120

Flow

rate

, cm

3 /s

20

15

10

5

0

Flow rate40 cm3/s

Flow rate22 cm3/s

DrawdownDrawdown

Quartz gauge pressure,Sample line pressure

45-mD/cP Mobility Reservoir 880-mD/cP Mobility Reservoir

Pumpout totalflow rate

Fluorescence Channel 0

Fluorescence Ratio

Fluorescence Reflection

Fluorescence Channel 1

Quartz gauge pressure,Sample line pressure

Pumpout totalflow rate

0

0.5

1.0

1.5

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3.0

3.5

Fluorescence Channel 0

Fluorescence Ratio

Fluorescence Reflection

Fluorescence Channel 1

100

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0

Elapsed time, min0 10 20 30 40 50 60 70 80 90 100 110 120

100

80

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10 min 30 min

The Quicksilver Probe tool design shortens time on station, and DFA technology provides engineers with critical and timely knowledge about reservoir fluids as they are captured. Both these advances have allowed operators to gather pressure and fluid sample data more quickly and with greater confidence in the results.

The Saturn probe expands the range of situa-tions and conditions in which WFTs are applicable; these include low-permeability or unconsolidated formations, heavy oil, near-critical fluids and rugose boreholes. The Saturn probe openings are configured to create a total surface flow area 1,200% greater than that of the largest conven-tional single-probe formation testers. This larger area means flow of viscous fluids is less restricted

and pressure differentials are reduced; viscous fluid flow and pressure differentials are the pri-mary constraints to testing in formerly inaccessi-ble environments.

In addition to allowing operators to take mea-surements and samples in these formations, in most cases the Saturn probe works to more quickly dispose of filtrate and contaminated for-mation fluids, reducing time on station. Constant-drawdown simulations in low-mobility reservoirs show the Saturn tool to be orders of magnitude faster than standard XLD packer probes in com-pleting cleanup. With no sump, transient flow regimes can be recognized earlier, extending the range of applicability of interval pressure tran-sient tests.

Shorter operating time is not trivial on some of today’s projects in which operating costs often exceed $US 1 million per day. The Saturn probe addresses this issue of high-cost time through higher flow rates that save operators hours and even days of operating expense. Similarly, data from the Saturn probe allow engineers to make critical completion and production decisions based on hard facts rather than estimates, and that can make the difference between success or failure, profit or loss. —RvF