New Dimensions in Wireline Formation Testing

Transcription

1 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 Corre Abbeville, France Mauro Firinu Eni SpA E&P Ravenna, Italy Germán García Mexico City, Mexico Morten R. Kristensen Abu Dhabi, UAE Michael O Keefe London, England Thomas Pfeiffer Stavanger, Norway Chris Tevis Sugar Land, Texas, USA Luigi Zappalorto Eni Norge SA Stavanger, Norway Murat Zeybek Dhahran, Saudi Arabia Oilfield Review Spring 213: 25, no. 1. Copyright 213 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 21): Oilfield Review

2 Borehole fluid Inflatable packer Packer assembly Fluid intake opening for WFT Pistons Probe 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. > 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. Engineers seeking to characterize reservoirs and design completions for maximum production efficiency 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 petrophysicists use a variety of data to make accurate reserves estimates and create representative reservoir models. These include fluid composition, pore pressure measurements, reservoir temperature, 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 continue to provide engineers with useful data about reservoir fluids, reservoir size and production potential. But characterizing fluids from samples captured at the surface can be problematic. 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 necessary for accurate analysis. In the 195s, the industry began addressing these and other sampling difficulties by introducing 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 formation 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 formation, 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 wireline engineers take formation samples. Sample bottles maintain the fluids at formation pressure to avoid phase changes while the samples are being retrieved to the surface for transport to a laboratory for analysis. 1 Spring

3 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 formations where establishing a seal was difficult. In addition, testing formations in which fluids move slowly to the tool prolonged the time the tool was on station and often resulted in samples that were contaminated 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 drawdown, or differential pressure, may exceed the ratings 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 relatively pure sample of reservoir fluids, engineers use a pumpout module a miniature pump level Guard intake Seal Time Acceptable sample Sample intake Contaminated intake Seal 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 laboratories for analyses. Under any condition, obtaining a representative 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 information 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 contaminants 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 samples, 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 reservoir fluid tester, which uses two concentric Flow tube to sample chambers Flow tube to wellbore > 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. 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 representative inner section of the conical flow, which may then be diverted into the WFT sample bottles (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 sampling 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 Challenges In most formation types, enhancements to WFT technology have greatly increased an operator s ability to capture representative fluid samples suitable for analysis while obtaining highly accurate downhole pressures. But operational constraints, unconsolidated sands, heavy oils and low-permeability rock still impact sampling success. Traditional dual straddle packers offer one solution for these conditions. However, this solution 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 significantly extend cleanup times and create problems for transient testing measurements in low-permeability reservoirs. 5 In the testing of low-mobility formations, drawdown pressures during pumpout may become quite high. The resulting differential pressures can exceed existing straddle packer ratings of about 31 MPa [4,5 psi]. High differential pressures may also result from flowing high-viscosity fluid through unconsolidated sands, causing seal failure or even borehole wall collapse. 34 Oilfield Review

4 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 typically 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 1-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 4 MPa [5,8 psi]. DFA measurements also help ensure sample purity and enable a different set of complex fluid analyses 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 significantly larger flow area between the formation and the tool while simultaneously providing a better sealing element. Inflatable packer Fluid intake ports 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 formation (right). The packer used in the Saturn probe seals more reliably against a rugose borehole than single-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 formation test times is the period required to flow the well until contamination of the reservoir 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 Saturn 3D Radial Probe The Saturn 3D radial probe, which uses four ports, increases the probe surface area to more than 5 times that of the standard probe. Elliptical Probe 6.3 Extra Large Diameter Probe 2.1 > 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). 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 26/27): Quicksilver Probe Probe 1.1 Large Diameter Probe.85 Standard Probe 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 29/21): 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. Spring

5 Common Parameters Porosity Horizontal permeability Vertical permeability Wellbore diameter Formation thickness Tool distance from boundary Formation pressure Maximum drawdown during cleanup Maximum pumpout rate Depth of filtrate invasion Miscible Cleanup Parameters Oil viscosity Oil-base mud filtrate viscosity Model Output Oil viscosity Water-base mud filtrate viscosity Relative permeability Residual oil saturation Irreducible water saturation Water relative permeability Oil relative permeability Water and oil core exponents Connate water saturation Model Output Saturn 3D radial probe XLD probe Saturn speedup over XLD probe Miscible Cleanup.71 h 9.1 h 12.8 > 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. 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 1.2 m [4 in.]. extra large diameter (XLD) probe. The team used ECLIPSE reservoir simulation software on three probe configurations to test the proposition. A fine grid was used to model the XLD and Saturn probes. For miscible contamination, investigators simulated a single-phase fluid system 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 considered parameters such as permeability, anisotropy, viscosity contrast between filtrate and oil, dispersion 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 Value 2% 1 md 2 md 21.6 cm [8.5 in.] 5 m [164 ft] 25 m [82 ft] 21 MPa [3, psi] 4 MPa [6 psi] 25 cm 3 /s [.4 galus/min] 1 cm [4 in.] Water-wet and Immiscible Cleanup, Water-Wet.42 h 7.17 h 17. Value 1 cp 1 cp Value 1 cp.6 cp Oil-wet and Immiscible Cleanup, Oil-Wet.99 h h D radial module with less total volume pumped. In a simulation of immiscible contamination cleanup, mud filtrate viscosities of 1. cp [1. mpa.s] and.6 cp [.6 mpa.s] were used. In scenarios using typical water- and oil-wet relative permeability, cleanup times to reach 5% contamination were similar to those for miscible contamination (above). 6 Because mobilizing heavy fluids often generates 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 permeability, drawdown pressure and cross-sectional surface area and inversely proportional to fluid viscosity and the length over which the drawdown is applied. By introducing a flow area about 4 times larger than that of traditional XLD probes, the Saturn probe reduces the necessary 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 drawdown 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 traditional probes, they create large storage volumes 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-permeability formations, heavy oils, unconsolidated formations, single-phase fluids close to the bubblepoint, ultratight formations and others. 7 Putting Theory to the Test An operator deployed the Saturn tool to distinguish between oil and water zones in formations that had been difficult to test using traditional tools. Among the problems was a history of formation 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 capture samples using traditional probes. Engineers viewed this operation as an opportunity to compare the Saturn tool with traditional sampling methods. They designed a WFT toolstring 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 , presented at the SPE Annual Technical Conference and Exhibition, San Antonio, Texas, USA, October 8 1, Mobility is the ratio of formation permeability to fluid viscosity. Therefore, lower formation permeability or higher fluid viscosity decreases mobility. 36 Oilfield Review

6 and seven samples were captured as the toolstring was retrieved from the well. At the first station, samples were captured using the XLD probe after DFA measurements had identified 6% to 7% oil in the flow stream. The operator chose Station 2 in an effort to determine 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,-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 [68 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. galus] pumped during cleanup (below). Even accounting for the XLD probe contribution, engineers concluded that oil arrived at the tool faster Saturn Probe XLD Probe Time 1 Time 2 Time 3 Time > 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.) Thermal Neutron Porosity Resistivity % 6-in. Array Induction Formation Density g/cm 3 3-in. Array Induction Delta-T Sonic Porosity % 2-in. Array Induction Lithology Porosity 53 Pretest Mobility md/cp Formation Pressure psi , Bulk Density Correction g/cm 3 Photoelectric Factor 1-in. Array Induction Invaded Zone Resistivity Fluid Type MDT Station Sandstone Limestone Dolomite 46 Station psi/ft (oil) 7% water 3% oil 48 4% water 6% oil Station 1 49 water Station psi/ft (water) ±.21 psi/ft > 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. Spring

7 Gauge pressure, psi 2, Quartz pressure gauge (observation) pressure 11 1,8 1 1,6 9 1,4 8 Saturn 3D radial probe pressure 1,2 7 1, Volume pumped Rate pump Rate pump 1 1, 2, 3, 4, 5, 6, 7, Elapsed time, s Volume pumped, 1, cm Pumpout rate, cm 3 /s > 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 2,5 s, the tool is set and pumpout begins, followed by a buildup beginning at about 1, 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, s to begin cleanup. At around 4, 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, 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 cm 3 /s for the first and second pumps, respectively. (Adapted from Flores de Dios et al, reference 1.) using the Saturn probe, which they attributed to the increased flow rate and radial cleanup. The operator also tested a low-porosity, lowresistivity 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. galus/h]. Using the Saturn probe, engineers were able to reduce drawdown to 7.6 MPa [1,1 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 measurements 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 standard 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.7. In this instance, in which traditional sampling techniques 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 Challenge Heavy oil is particularly problematic for conventional 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 critical for operators to be aware of higher-mobility zones within the reservoir layers created by relatively 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 211, the national oil company of Mexico, Petróleos Mexicanos (PEMEX), reported 6% 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 important to PEMEX and the nation. In the Samaria heavy-oil field in southern Mexico, PEMEX is trying to produce fluids with viscosities at downhole conditions as high as 5, cp [5, mpa.s] from formations with unconfined compressive strength of from.69 to 5.5 MPa [1 to 8 psi]. 1 Because of challenges presented by the combination of high-viscosity 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 perforated 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 development cycle in these Tertiary-age sandstones, they turned to the Saturn probe in 211 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 sampling. In the fourth well, they also planned interval 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 8. Al-Otaibi et al, reference Petróleos Mexicanos (PEMEX) Exploración y Producción: 211: Las reservas de hidrocarburos de México, Mexico City: PEMEX (January 1, 211): 22 (in Spanish). 1. 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 , presented at the SPE Annual Technical Conference and Exhibition, San Antonio, Texas, October 8 1, Flores de Dios et al, reference Oilfield Review

8 1 3 Modeled delta P, Saturn tool Delta P and derivative, psi Modeled derivative, Saturn tool Modeled derivative, WFT observation probe Modeled delta P, WFT observation probe Time since end of drawdown, s > WFT interference test. The Saturn probe was run beneath a single-probe WFT. Engineers conducted an interval pressure transient test, obtaining vertical permeability (k v ) and horizontal permeability (k h ). 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, 64 md, 12 md and 37 cp for height, k v, k h 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 1.) 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 setting and unsetting time, minimum inflation pressure for a seal and optimal pretest volume to account for storage effects. The Saturn probe achieved 1% sealing in each of the seven stations tested using packer inflation pressures as low as.2 MPa [3 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 differential pressures that would require 16 to 2 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 differential pressure rose to about 2 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 3-psi [2.1-MPa] differential minimum for Station 2 (previous page). The minimally contaminated sample collected at this station was 7.5 API gravity oil; subsequent laboratory analysis documented that this sample had a viscosity of approximately 1,3 cp [1.3 Pa.s] at downhole conditions and about 7,8 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 interval pressure transient tests using the Saturn probe combined with an observation probe. These transient 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 engineers are applying this information to calibrate cutoffs in nuclear magnetic resonance log processing, which they use to fine-tune permeability predictions. 11 Low Mobility and High Confidence Using resistivity log measurements, petrophysicists are able to delineate oil/water contacts in the majority of formations. However, in some formations, 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 determine the extent of an oil zone in a tight carbonate 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 measurements using traditional downhole sampling tools was precluded because establishing flow from the tight carbonate formation would have created a differential pressure greater than traditional dual packer ratings. Spring

9 Pressure, psi 5,5 5, 4,5 4, 3,5 3, 2,5 Thermal Neutron Porosity % Formation Density g/cm 3 Sonic Porosity % Bulk Density Correction g/cm 3 Photoelectric Factor Resistivity 6-in. Array Induction 3-in. Array Induction 2-in. Array Induction 1-in. Array Induction Invaded Zone Resistivity 4,9-psi pressure differential 2, 1 1,5 Pressure 1, Rate 5 5 1, 2, 3, 4, 5, 6, Time, s > 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 4,9 psi (bottom), which exceeds traditional WFT and packer ratings. (Adapted from Al-Otaibi et al, reference 6.) 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 4,9-psi [34-MPa] differential pressure from the.4-md/cp mobility zone, DFA measurements indicated the presence of mobile light oil in the middle zone, which allowed the operator to determine that the thickness of the oil zone was greater than initial estimates (above). Fluid Type Water MDT Station Lithology Porosity Limestone Dolomite Clay Sandstone Flow rate, cm 3 /s Drawdown Restrictions In some instances, operators have reason to use the Saturn 3D radial probe, even though a traditional one might suffice. After engineers at Eni SpA saw the results achieved using the new probe in Ghana, engineers at an affiliated company, 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 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 column. 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 gradient and log response. Furthermore, because of the large flow area of the Saturn probe, the strength of the laminated 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.5 bar [.5 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 88 md/cp more than an order of magnitude 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 Forward The industry s ability to capture fluid samples and critical pressure data has evolved rapidly since the 197s. Innovations in these arenas have been spurred by need to develop more-complex formations 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. 4 Oilfield Review

10 mD/cP Mobility Reservoir 5 88-mD/cP Mobility Reservoir Quartz gauge pressure, Sample line pressure Drawdown Quartz gauge pressure, Sample line pressure Drawdown Pressure, bar Pumpout total flow rate Flow rate 4 cm 3 /s Flow rate, cm 3 /s Pressure, bar Pumpout total flow rate Flow rate 22 cm 3 /s Flow rate, cm 3 /s Elapsed time, min Elapsed time, min Fluorescence Fluorescence Channel Fluorescence Channel 1 Fluorescence Ratio Fluorescence Reflection Fluorescence Fluorescence Channel Fluorescence Channel 1 Fluorescence Ratio Fluorescence Reflection 1 1 Fluid fraction, % min 2 3 min Fluid fraction, % Elapsed time, min Oil Water Elapsed time, min Mud-contaminated fluid > 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 88-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 1 minutes (bottom left) compared with the XLD probe, which cleaned up in about 3 minutes (bottom right). 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 situations 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 1,2% greater than that of the largest conventional 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 primary constraints to testing in formerly inaccessible environments. In addition to allowing operators to take measurements and samples in these formations, in most cases the Saturn probe works to more quickly dispose of filtrate and contaminated formation fluids, reducing time on station. Constantdrawdown simulations in low-mobility reservoirs show the Saturn tool to be orders of magnitude faster than standard XLD packer probes in completing cleanup. With no sump, transient flow regimes can be recognized earlier, extending the range of applicability of interval pressure transient 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 Spring