HPHT LWD & EWL formation testing SPWLA 2006

SPWLA 47th Annual Logging Symposium, June 4-7, 2006

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COMPREHENSIVE FORMATION EVALUATION IN HP/HT EXPLORATION USING OIL BASED MUD: FORMATION PRESSURE

WHILE DRILLING (FPWD), WIRELINE FORMATION TESTING (WFT) AND FLUID SAMPLING

Mohamed Hashem, Alan McHardy, Mike Wynne, Wilfred Pool, Taco Viets, Christof Keuser,

Shell Exploration & Production, Kåre Otto Eriksen, Statoil.

Copyright 2006, held jointly by the Society of Petrophysicists and Well Log Analysts (SPWLA) and the submitting authors.

This paper was prepared for presentation at the SPWLA 47th Annual Logging Symposium held in Veracruz, Mexico, June 4-7, 2006.

ABSTRACT An exploration well was evaluated offshore in the Norwegian Sea. This was an HP/HT well with temperatures of the deepest reservoirs exceeding 180 degree C and pressure over 800 bar. The well was drilled with oil-based mud. After penetrating top reservoir, a formation pressure while drilling tool (FPWD) was deployed. Subsequently conventional wireline formation pressures, samples and mini-DST,s were acquired followed by standard DST tests. This was the first application of the FPWD tool in a vertical well from a floating rig. Procedures were established to restrict tool motion. The objectives for running the FPWD tool were to measure formation pressure to within +/- 72.5 psi (5 bars) in order to optimise mud weight. Initially the well was approximately 690 psi overbalanced, this was subsequently dropped to approximately 320 psi. In the planning stages the dynamic wellbore situation was acknowledged. It was planned to acquire repeat points subject to variations in circulation rate. This was to investigate diffusion due to incomplete filtercake development, and healing processes in the formation. The data obtained demonstrate an ~ 83 psi decrease in stabilised (not building) pressure, at the same depth, with decreasing circulation rate and increasing exposure time. This reflects the equilibration process that diffuses the mud invasion with time. The effect of circulation (annular pressure) can be observed on some pressure build-up plots, reflecting the dynamic effect on the near well bore region. The last FPWD point, obtained with no circulation, falls within 3 psi of the extrapolation to shallower depth of the fluid-sample

calibrated gradient obtained from subsequent wireline formation tester acquisition. Subsequent attempts to obtain wireline formation pressures failed (tight tests) in the region where FPWD data was successfully acquired. It is thought that the small drawdown and storage volume of the FPWD tool facilitates the acquisition of pressure data in low reservoir quality environments. Also, wireline mobilities may be reduced due to particle plugging from CaCO3 additives and low gravity solids from drilling through hard, quartz cemented sandstone After the well was successfully cored, rock and fluids properties were further evaluated. Due to the (HPHT) nature of the well, coupled with the synthetic oil-based mud used, the evaluation options were limited. Extensive planning was conducted and the Reservoir Characterization Instrument (RCI) from Baker Atlas was chosen for the task. Fluid samples acquired were successful in identifying fluid types, were of low OBM contamination by volume reservoir fluid, and successfully detected H2S despite relatively low concentrations in the reservoir fluid (as indicated from DST). After correcting for OBM contamination, the CGR results were within 2-4 bbl/MMCF from the well tests. WFT cannot measure CGR values lower than 1.5 to 2 bbl/MMCF, when sampled with OBM, due to unavoidable contamination inside the tool. The compositions derived from the RCI across the same intervals as DSTs, were mostly in agreement. Mudlogging isotope data can be an aid in reconciling separate datasets. The dual packer elements of the RCI tool were successfully deployed in an HPHT environment for transient pressure testing (mini-DSTs). Permeability was successfully investigated and was in close comparison with core permeabilities, given the uncertainties in each measurement. This

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SPWLA 47 Annual Logging Symposium, June 4-7, 2006th


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provided valuable early productivity information with which to optimise the further well data acquisition (full DSTs), in addition to providing productivity data in zones not subjected to full DST.

WFT evaluation objectives were largely met, a significant achievement given the challenges involved. Uncertainties in the reservoir quality and fluid properties still remain. The wireline data is not a replacement for DST. They see the geology at differing scales and thus are mutually complementary. We will review the planning and execution of the wireline campaign and the comparison to the well test results with a view to further appraisal. INRODUCTION The paper summarises the data acquisition planning, execution and results from a well drilled in extremely challenging environment. Temperatures of the deepest reservoirs exceeded 180 degree C and pressure over 800 bars. World 1st achievements were made in terms of vertical LWD FPWD acquisition and EWL Dual Packer setting temperatures. DST testing of all reservoirs was impossible due to rig availability constraints. LWD, mud logging core, and wireline data were vital in not only “filling in the gaps” but also giving data at a high resolution, in order to aid understanding of reservoir complexity. FORMATION PRESSURE WHILE DRILLING Objectives of the FPWD data - Exploration licence commitments dictated the requirement to acquire core. Mud weights upon reservoir entry catered for the P90 pore pressure estimate. A formation pressure estimate was therefore required to optimise the mudweight prior to coring, avoiding any well control issues. A Formation pressure while drilling (FPWD) tool was selected in order to minimise use of rig time and also to enable immediate alteration of mudweight prior to pooh. The objective was to measure formation pressure to within +/- 72.5 psi (5 bar). Operational considerations - The use of the FPWD tool posed many operational challenges. This was the first application of this tool in a vertical well from a floating rig. The data was to be acquired during winter in the Norwegian Sea. The FPWD

tool operates with a probe, mounted on a stabilizer blade. In this situation, heave can result in tool motion downhole, which could interfere with the formation seal and damage the tool. In order to mitigate this risk, specific operational procedures were established. These included, use of wave motion compensators, closing BOP rams to increase drag, and deploying the tool with the drill bit on-bottom with WOB applied. This latter tactic used the elasticity of the drill string to absorb the rig motion. The operational approach had implications for the data acquisition and selection of zones with the highest reservoir quality was difficult. Reliable quality GR and resistivity data in real time was required ahead of the tool. Possibly the most important effect of having the bit on bottom was that the elapsed time after drilling was short. Getting the data - Due to the limited formation exposure time there was uncertainty as to the effect of dynamic mud invasion. One school of thought advocated that in this situation the elapsed time was so short that invasion had not occurred, facilitating quality data acquisition. Alternatively, the invasion process could be active, adversely affecting the chance of achieving the data objectives. The acquisition programme was designed to investigate the uncertainties discussed, with repeat (time lapse) points, subject to changes in circulation rate acquired. Tests entailed a preliminary short drawdown, from which the rate and drawdown were used to optimise the main drawdown volume in order to maximize the chance of getting a stabilised pressure. Finally, a formation pressure point was obtained with no circulation. RESULTS OF FPWD A total of 12 points were acquired, from 6 separate depths, spanning two formations. The first 3 points were measured in a formation that proved to be shaled out in this area. The latter (deeper) 9 points were measured in a medium / low quality sandstone (c.0.1 – 5mD). Overall, four points were classified as not stabilised, and 8 were classed as stabilised or stabilising. As will be shown, subsequent data demonstrates all but one of the points to be above formation pressure, but with the final point proving to lay almost precisely at extrapolated formation pressure. Mobilities calculated ranged from 0.2 to 1.36 md/cp. Results are summarized in Table 1.

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Non-stabilised pressure - An example of a non-stabilised pressure test is given in figure 1. The pretest volume was small (0.18 cc) and the probe pressure is clearly still building, and is supercharged. The calculated mobility was low (0.8 md/cp) but unreliable. The drawdown response suggests a good seal was obtained with the borehole wall. The pressure buildup curve displays oscillations, which correlate closely with oscillations associated with mud circulation, as measured by the annulus pressure sensor and also plotted on figure 1. It is inferred that invasion is occurring dynamically into the near wellbore region and the Stethoscope gauge is measuring this effect. Stabilised pressure - Figure 2 illustrates the results of pressure test number 12. This pressure test was taken in pretest mode A (0.52 cc volume), with pumps off, and is classified as a good measurement. A clear drawdown is obtained, and the buildup is stabilised to an acceptable degree, the final buildup matches the initial pretest buildup closely. Tests number 8-12 were all taken from the same depth, and are all classed as stabilised buildups, analogous to this test. Circulation rate and exposure time - Figure 3 plots pressure points 8-12 as a function of circulation rate. A clear decreasing trend in pressure can be observed as the circulation rate is lowered. Test 8 and 9 were taken at 1800 and 1440 LPM respectively, a drop of 19.2 psi is observed. Test 10 and 11, taken at 1785 and 1420 LPM; show a decrease of 11.3 psi in stabilised build up pressure. Point 12 was obtained with no circulation (pumps-off). A large decrease in pressure can be observed between test pairs 8/9 and 10/11. This decrease relates to the increase in formation exposure time; figure 4 plots pressure points 8-12 as a function of this exposure time. The data shows a clear decrease in pressure with increased exposure time. Between points 9 and point 11, taken at similar circulation rates (1440 / 1420 LPM), the pressure dropped by 56 psi. Taken in combination, figures 3 and 4 show that a decreasing circulation rate has some effect on measured pressure, but that overall the exposure time is having the greatest significance. It is doubtful that the final (formation) pressure (point 12) could have been achieved simply by turning the pumps off immediately after points 8 and 9 were obtained. A “pseudo measurement” (9a) is inferred

by extrapolation; superimposing the shape of pressure decline trend obtained from sequence 10-11-12, onto sequence 8-9. This gives pressure with pumps off, of approximately 11670 psi, still more than 50 psi supercharged. Comparison to traditional wireline pressures Subsequent to drilling, traditional wireline formation test (WFT) pressure data were acquired (further discussed later). Figure 5 compares the wireline derived pressure gradient with the FPWD data points 10-12. The wireline gradient has been extrapolated upwards from the shallowest data point; it is not thought to transcend separate reservoirs (pressure regimes). The gradient has been calibrated to a downhole fluid sample, in addition to pressures obtained after fluid sampling and dual packer testing. These pressures are considered high quality since all supercharging and drilling fluid has been pumped out of the formation. The final FPWD point (point 12 pumps-off) falls (to within relevant uncertainties) upon the gradient. The data in figures 3, 4 & 5 demonstrate that all the stabilised measurements that were taken with pumps-on (8-11) were in fact supercharged. However the pumps-off measurement was not. Furthermore, the direct influence of both the circulation rate and exposure time on the stabilised build-up pressure can be observed. Low mobility environments - In the area where FPWD data was successfully acquired, the formation subsequently proved too tight to obtain wireline pressure measurements. This could be due to a number of reasons; it is possible that plugging (formation damage) has occurred by solids in the drilling fluid (CaCO3 additives and/or small particle size low gravity solids from drilling through quartz cemented sandstone) or, the comparative storage volume of the wireline tool compared to that of the FPWD could be responsible. DISCUSSION OF FPWD DATA A decrease in stabilised pressure of 83 psi was observed (at the same depth) due to a decrease in circulation rate and increasing exposure time. The data demonstrated the presence of stabilized formation pressures that are clearly supercharged. This is thought to be due to incomplete filter cake development, and possible erosion of filter cake when circulating. This gives rise to a lengthened

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and potentially dynamic pressure gradient from borehole to formation, rather than a clear pressure barrier provided by a well-developed filter cake. Wellbore healing is incomplete, invasion is ongoing, and pressure equilibration has not occurred. It would have been impossible to derive a fluid pressure gradient from the FPWD tool in this example. In future operations, where repeat points like this may not be possible, clear thought should be given to the effects described here. Operational procedures such as minimizing circulation rate, and maximizing time after drilling may prove to be beneficial (Pop 2005) in addition to minimizing the amount of reaming which is done over the intended pressure point. However in tools such as this where the probe is mounted on a stabilizer blade, it may be difficult to avoid disturbance of the filter cake. A good practice when acquiring time lapsed FPWD data is to pull straight up to the test depth (if possible) and avoid rotation with stabilizers across the area where the probe is to be set. The objectives of the data acquisition were met, and mud overbalance was dropped from approximately 690 psi to 320 psi. Four cores were successfully obtained. Full cooperation and communication during planning and operations, between all disciplines in the operator and contractor companies was instrumental in acquiring successful data. PLANNING THE WIRELINE EVALUATION Due to the nature of the well coupled with the synthetic oil-based mud used, the wireline formation tester options were limited. The RCI tool from Baker Atlas was selected for its Dual Packer capabilities. Preparation meetings were conducted to plan the job for HPHT. These involved the operator subsurface and well engineering teams, in house and partner specialists, service company specialists, the fluid transfer company, and the PVT laboratory. Plans were made for repeated runs to minimize exposure to elevated temperatures. Two back-up tools were put on location. Specific tests were undertaken in order to heat qualify the tools. The WFT evaluation objectives were set as: 1. Acquire pressures to represent the zone fluid

gradient,. 2. Determine contacts using gradients and verify

using “Gargling Technique” (Hashem 1999).

3. Acquire representative samples of all zones, and test for compositional grading.

4. Profile the reservoir permeability, using Dual-Packer mini-DST and probe, pressure transient analysis

5. If possible, check for H2S presence in reservoir fluids.

There was uncertainty whether the tool would survive the heat and complete the evaluation objectives before failure. The evaluation objectives were ranked and prioritised accordingly. The first WFT run was for pressures and to investigate operating temperatures. The second run was to acquire fluid samples, and the third to perform mini-DST. Dual Packer use was minimized as it was recognized that this module was the most temperature sensitive device in the tool string. Inflation in these environments can deform the rubber elements and cause them to rupture. It is also much quicker to set and unset the probe. Accordingly, samples would only be attempted using the packer in zones that could not be sampled with the probe; these stations would then be candidates for mini-DST. In this scenario, after carefully acquiring a fluid sample using the Dual Packer, we would pump at maximum rate allowable by the pump out module, for a flow period, and then shut in for a period sufficient to establish radial flow, starting with assumption of twice the flow period (Kuchuk 1998) (real time diagnostic plots were used for determination of shut in time). In the case that all samples are successfully acquired with the probe, then a mini-DST test would be performed over selective zones for permeability information. It was important to prioritize acquisition in order to collect maximum value information prior to an expected tool failure. The zones were ranked according to their relative importance. Pressure measurements in these zones were to be acquired going down, followed by sampling the same zone. If one were to land on a permeable streak, sampling that point should be immediately considered. Sampling Planning - The high-pressure pump (6000 psi differential) with 434 cc/stroke was chosen to maximize the ability to pump fluids from low permeability rocks. One should be careful not to flash the pumped fluids with excessive drawdown, but in this situation, the reservoir fluids were sufficiently under saturated to avoid flashing

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even when maximum drawdown from the pump was used. The samples were to be obtained in an upward direction using low shock techniques (Crombie et..al. 1998). Diverting fluids downwards in the tool can lead to collection of heavier mud filtrate in the sample bottles during opening. The filtrate fluids exist in the dead ends and crevices and are bypassed during clean-up pumping due to the controlled flowing pressure. This phenomenon is exacerbated in tool systems where the pump has to be stopped in order to enable the hydraulic system to operate the valves of the sample bottle, thus providing the time to allow heavier filtrate fluids to enter the sample bottle. Conversely, sampling upwards allows for the tool flow line to act as a sump for collecting such fluids, thus ensuring that only lighter formation gas enters the bottles. The low shock technique entails that after successfully filling of a sample bottle, it is then over pressured by the maximum amount the pump can deliver, in this case 6000 psi. Sample Preservation Planning - The temperature contrast between the reservoir and the surface (latitude 64Deg North) was of concern (Hashem 2004). If the expected reservoir gas sample is exposed to low temperatures, the pressure could easily fall below dew point, liquid condensate can then mix with any liquid contaminant from the SOBM that may exist in the bottle. Correcting for this is problematic, as for some light gas systems; some of the remaining gas components can be absorbed back into this new liquid phase. Even re-pressurizing and reheating these samples may not put all the condensed liquid back into a single-phase gas system. Therefore it was planned to keep the temperature and pressure of the recovered samples as high as possible. Nitrogen compensated bottles were to be used, but there were doubts about the probable efficiency of the pressure compensation. Thus two types of bottles were used for the first sampling run, with nitrogen and without nitrogen, in order to assess the success or failure. The rigging down sequence of the tool should allow for quick recovery of the sampled bottles in order to minimize their heat loss. H2S Planning - The low expected concentrations of H2S present in the reservoir fluids dictated a well inhibiting system in order to minimse H2S exchange between reservoir fluid and metals in the tool. The all titanium construction of the selected RCI tool,

and the sample bottles material (NP35) meant that this should be achievable. A laboratory test was designed for the RCI (Shammai 2004) where gas containing low concentrations of H2S was flowed from a tank through an equivalent tool string to that to be run in the well. H2S levels were measured periodically at the exit port of the tool and in the sample bottles. Comparison of concentrations before and after the pumping found 3 – 5 ppm scavenging through the tool, the results of the study are summarised in Table 3. Comparison of H2S concentration between WFT and well test, are presented in the results comparison. Real Time Data Transmission - It is important to start with a flexible plan, evaluate the formation parameters, and adjust the plans accordingly. Many variables can affect the outcome of a complex WFT operation, each requiring a different reaction. Close follow up of the job in real time is essential. This can best be done through real time data transmission and “hands on” support from onshore WFT specialists and relevant subsurface team (Elshahawi 2005). The task cannot be delegated to the service company engineer alone or an unqualified company representative on location. The job starts with caution until key parameters, such as the degree of over balance, hole condition, operating temperature, reservoir fluid types and permeabilities are defined. Subsequently the priorities and plan for further gradient work, fluid sampling and transient testing can be revised. The entire team presence ensures that a comprehensive informed decision is made. Tool String Design-1st planned run - The first WFT pressure run had a significant element of reconnaissance in order to determine the temperature, mobility profile and amount of over balance. The configuration was reduced to minimum components as follows (listed bottom to top); GR-Probe-DD pump- Electronics-Hydraulics-Telemetry and Power. 2nd planned run - The second run was planned for the sampling using probes. The configuration was as follows; GR- Probe - DD pump -6000 psi large displacement pump (434cc/stroke) - Sample View – 2 x 6 Tank

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carriers - Electronics- Hydraulics -Telemetry and Power 3rd planned run - Third run was planned to carry out any sampling and mini-DST using the dual packer, if possible. The configuration was as follows; GR - Dual Packer - Probe - 6000 psi large displacement pump (434cc/stroke) - Sample View - – 2 x 6 Tank carriers - Electronics- Hydraulics -Telemetry and Power In all cases the GR was at bottom, as it was required to detect the clean formation closest to the bottom of the sand, with the GR tool on the top there was not enough rathole to secure this option. Job Execution The first run (pressure only) achieved 40 pressure measurements, each with multi drawdowns. Moderate levels of over balance were observed (mud weight had already been dropped after acquisition of FPWD data) and a reasonable range of formation mobilities existed, so the pretests would require shorter time on station generally. In the zone where FPWD data had been successfully obtained, no pressures were possible – see FPWD results section. Based on the observed logging temperature, which was close to expectations of 180 degrees C in the deeper part of the well, it was decided to lower the well temperature with a wiper trip prior to continuing with the operation.. The 2nd (sampling) run achieved 3 sample depths and eleven pressure stations. Permeability measurements from cores and pretest from the first run were used to prioritize sampling stations. Three to four bottles were filled at each depth, with a continuous account for bottles filled and unfilled. Having redundancy safeguards data acquisition against unfilled bottles and analysis uncertainties. At surface temperature the bottles indicated a large pressure drop from the sampled reservoir pressure, despite the fact that all bottles were over-pressured downhole using the pump. Despite this pressure loss, the nitrogen compensated bottles were used again in the follow up sampling, as they were successful in keeping the bottles above a range of potential dew point pressures.

The third run was for mini-DST pressure transient data. The packer module is a tried and tested tool but, at the time of acquisition, only in lower temperatures than those encountered here. The module had never been exposed in an operational environment to the extreme conditions found. The formation tested varied from a fraction of a milli Darcy to hundreds of milli Darcy. The temperature at the time was in the region 160 to 175 degree C. There were two successful packer-setting depths before failure on the third setting. The first packer test was over a very low permeability zone, pumping had to be halted for periods because the pressure differential across the packers approached the advised limit. The second packer test was over a zone of high permeability (expected to be 100’s of mD’s from logs and the WFT probe). The large pump had failed due to the heat, and the pumping tasks were carried out using the low volume 50-cc/stroke pump. The low volume pump was not capable of creating a signal large enough for any meaningful mini-DST analysis. This did confirm that it was an extremely high permeable zone. A fourth run involved a replacement of the failed pump. There were two successful tests (see results comparison) before the third setting failed. This concluded the programme and the data was analyzed immediately to aid the well test design. The real time monitoring demonstrated value in its ability to quality control the successful filling of sample bottles. Considering the bottle volume and the compressibility of the sampled fluids, one can count the number of strokes it takes to fill the bottle and over pressure it (Hashem 2003). If a premature increase in pressure is observed, or alternatively none at all, one can assume the filling of the bottle is questionable. Additional bottles could then be filled to ensure adequate volumes are collected from the higher priority zone, with the remaining samples obtained on the next run. The ability to diagnose problems and react accordingly is a great value that real time expert support team can deliver. RESULTS WFT – ROCK & FLUIDS Permeability - In total 4 successful mini-DST’s were acquired. Two of these overlapped with a cored interval, one with a DST, and one was standalone.

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1. The first mini-DST was aimed at a reservoir, which from core and log data looked to be of lesser quality. While pumping the tested interval proved very tight and the subsequent build-up never got out of tool storage making an accurate estimate of the permeability impossible. Nevertheless, the dual packer test indicated extremely low permeabilities and reinforced the concerns about the producibility of this zone.

2. Another mini-DST was performed on the same

zone but slightly deeper. This test resulted in a much more interpretable build-up as can be seen from the log-log diagnostic plot in figure 7. Although only just in radial flow, a permeability of around 0.2 mD could be interpreted, which is in good agreement with the in-situ corrected core plug measurements shown in figure 6 (in contrast to the NMR derived permeability indication, which is significantly higher). Based in part on the low permeabilities derived from these two mini-DST’s, a full DST on the whole zone was justified in order to investigate it’s overall productivity, but was cancelled due to rig availability.

3. A third mini-DST was designed to coincide

with an interval that was later tested. This failed to achieve adequate drawdown due to a combination of high permeability and failure of the large volume pump and therefore, unfortunately, no direct comparison of permeability was possible. Given that the main objective of the subsequent well test was obtaining representative fluid samples and that this requires good stable flow, the early indication of high permeability from the mini-DST gave the necessary confidence that that objective would be achievable with the full well test, hence derisking that high expenditure.

4. The final mini-DST was over an un-cored and

un-tested interval. The early transient data gave a good handle on the minimum permeability of the interval, but, regrettably, the later transient data was questionable, showing very doubtful proximal boundaries.

While this was a minor interval in terms of in place volume, the significance of this mini-DST lies in the fact that it proved (together with wireline samples) that this interval should be able to contribute to a future development, without the need for a full DST on the interval.

The data acquired has proven the technological feasibility of mini-DST at HPHT conditions in OBM. By the nature of methodology, and volume investigated, various sources of permeability information can be expected to give varying results. The marriage of these data sources into a consistent interpretation is the next logical step. Wireline mini-DST tests are a valuable tool to calibrate and compare to core plug measurements and fill in data gaps between intervals subjected to full DST. Fluid Contamination - The RCI samples were some of the first successfully acquired in such a challenging environment. The on site fluid analysis showed low OBM contamination in reservoir fluids (~1% of total sample volume), but because the gas was very dry, the filtrate volume of less than 1 c.c. represented about 50-70 % of the stock tank liquid content in the sample chamber. Such contamination levels by reservoir fluid volume in an HPHT well are judged a success by all means. It is worth mentioning that in one of DST’s the well was flowing for more than 60 hours before the contamination levels fell below 10 % in stock tank liquid, again, mainly due restricted clean up flow rate and the nature of this dry gas. If the gas was wetter it may not take as long as more OBM filtrate would go into solution with the gas phase. Similarly, the WFT samples would have achieved much lower stock tank liquid contamination levels. Fluid type - Pressure points taken during run 1 & 2 indicated the presence of at least 5 different reservoirs, but scatter in the pressures hampered positive identification of gas richness from the gradients. A total of 13 samples from 4 reservoir levels were successfully obtained, and they gave the final confirmation that all these reservoirs contained dry gas. Although disappointing compared to neighbouring fields, which mostly contain wet gas, this was crucial information for future development options of the discovery.

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Fluid CGR - Two of these reservoirs were subsequently tested. The CGR results from the RCI samples, after correcting for OBM contamination, were within 2-4 bbl/MMCF from the well test. Fluid Composition - Figure 8 shows wireline sample analysis compared to DST samples from an overlapping interval (upper DST). Four bottles were sampled at this location. Two show good agreement, one bottle came back empty, and one is anomalous, (third sample – 448 is clearly separate from the rest of the data). This outlying sample is not considered representative. This demonstrates the value of acquiring 4 samples at each station. Figures 8,9,10 illustrate ‘wellstream’ compositional analysis (after correction for OBM contamination and mathematical recombination of liquid and gas portions). In Figure 8 a decrease in C3-C5/C1 ratio can be observed between laboratory and field flashed samples. The field samples were flashed at lower temperatures resulting in more of the C3 and C4 entering the liquid phase. During subsampling for liquid gas chromatography, the chilled liquids warmed, losing the light hydrocarbons before analysis. This was also confirmed in samples from the other reservoir levels. C6+/C1 ratios in Figure 8 and Figure 9 show a decrease between Nitrogen compensated type bottles and the standard bottles. The standard bottles lack a check valve and so liquids (C6+) will be lost from these samples. Liquid that had condensed from the sample has probably been accumulated in the stem of the flowline below the bottle entry point, and has thus not made it into the final sample. The nitrogen compensated bottles do not suffer from this effect as they have a check valve (regardless of whether they are actually charged with nitrogen or not). Interestingly, the C6+ ratio in figure 10, where we have two nitrogen compensated bottles, the C6+ ratio increases for field compared to lab flash. The combination of bottle type, flash temperature, bottle opening pressure relative to it’s dew point and the contamination level are having subtle effects on the data, which are complex to demonstrate with a small data set. The ability to observe and understand all these effects strengthens the confidence in the data, and is ongoing.

Figure 10 compares compositions (as for figure 8) of wireline samples to DST (this time the lower DST). Clear contradiction between the DST and wireline data can be seen - however the wireline samples are internally consistent. Figure 11 is a depth plot of carbon isotope measurements taken from mud logging techniques. Also plotted are the same isotopes measured from DST and wireline samples. For the upper DST interval there is a good agreement between the three data sets. Deeper in the well there is good agreement between the mudlogging data and wireline samples for intervals not DST tested. The results are very revealing over the lower DST zone, where the contradiction between wireline and DST samples was observed (Figure 10). The mudlogging isotopes show a break, correlating to a gamma ray peak, approximately halfway down the DST interval. The isotopic composition of the DST matches the mudlogging data over the upper half (above the break), while the isotopes from the wireline sample match the mudlogging data over the lower half (below the gamma peak). Thus neither the DST nor wireline contradicts the mudlogging data. However, there are still questions; from neutron-density crossover (not plotted), by far and away the cleanest sand of this DST interval is actually the lower most part of the DST (i.e. below the isotope break /gamma peak). This would be the part expected to contribute most significantly to flow, and thus the DST sample would be expected to have that composition. However from the significant time taken to clean up during the test, it is thought that the upper lower quality sands were also flowing, and thus the DST sample could also be indicative of the fluids above the isotopic break. Certainly uncertainties remain here, but the data could be interpreted to indicate that this lower DST sampled fluids from either zone. It would appear we have some degree of vertical compartmentalisation, and although these zones were at same initial pressure from pressure gradient analysis, they may not be in full communication. Their behaviour on a production timescale would be of interest. In summary, low contamination (in reservoir fluid) wireline samples were acquired in a frontier technological environment; they are throughout indicative of reservoir fluid CGR and composition.

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H2S - The H2S concentration in the wireline samples was generally 15+ ppm lower than the well test samples (Table 2), implying greater scavenging than that observed in the laboratory tests. In this moderate concentration H2S environment (14-30ppm) the observed differences are proportionally large, and straddle the points where major step changes will be required in material selection for tubulars in development wells (13Cr, Duplex or Super Duplex steel). Under these circumstances, well test verification of the H2S concentrations is therefore recommended. Even though the wireline samples gave too low H2S concentration the result demonstrated to a certain degree the inhibitive ability of the RCI tool. At these low concentrations, detection of any H2S with a wireline sampler is a significant achievement. However more work needs to be done to further improve H2S sampling with wireline tools. CONCLUSIONS

• The FPWD successfully achieved its goal of optimizing the mud weight for coring.

• The dynamic invasion effects measured by the FPWD time lapse measurements showed that the pressure was not equilibrated to reservoir pressure many hours after the bit penetration.

• There is a difference between the FPWD measurements with the pumps on and the pumps off. With the pumps-on FPWD measured pressures were elevated around 1.5 bars.

• FPWD tool gave good pore pressure measurements, but pressure gradients are unobtainable from this tool.

• FPWD successfully measured tight reservoirs pressure where WFT failed, most likely due to smaller storage volume.

• WFT sampling can be successful in identifying fluid types even in HPHT/ OBM / low CGR environments.

• The CGR results from the RCI samples, after correcting for OBM contamination, were within 2-4 bbl/MMCF from the well tests.

• WFT cannot measure CGR values lower than 1.5 to 2 bbl/MMCF, when sampled

with OBM, due to unavoidable contamination inside the tool.

• The compositions derived from the RCI across the same intervals as DSTs, were mostly in agreement. Discrepancies exist and are under analysis.

• Mudlogging isotope data can be crucial in closing the loop between datasets.

• H2S was detected in a low concentration environment. The RCI tool is partially inhibitive of H2S scavenging, proven by laboratory test and well results. However, for development well and facility design purposes, well test verification of the H2S concentrations is recommended.

• The dual packer elements of the RCI tool were successfully deployed in an HPHT environment. The mini-DSTs performed with it provided valuable early productivity information with which to optimise the further well data acquisition (full DSTs), in addition to providing productivity data in zones lower down the DST priority list

• Given the uncertainties in each measurement method, permeabilities derived from RCI mini-DST’s were in close comparison with core permeabilities

• WFT evaluation objectives were largely met, a significant achievement given the challenges involved. As is to be expected, uncertainties remain, which will be the focus of further appraisal data acquisition.

References Chang, Y., Hammond, P. S., and Pop, J.: “When Should We Worry About Supercharging in Formation Pressure While Drilling Measurements?” paper SPE/IADC 92380 presented at the drilling conference held in Amsterdam, Netherlands, 23-25 February 2005. Crombie, A., Halford, F., Hashem, M., McNeil, R., Thomas, E. C., Melbourne, G. and Mullins, O.: “Innovations in Wireline Fluid Sampling” in Oilfield Review, Vol. 10. No. 3. 1998 Elshahawi, H., Hashem, M., McKinney, D., Ardila, M. and Ayan, C.: “The Power of Real-Time Monitoring and Interpretation in Wireline

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Formation Testing-Case Studies” SPE94708 presented at the 2005 SPE Annual Technical Conference and Exhibition held in Dallas, Texas, U.S.A., 9 – 12 October 2005 Hashem, M.N., Thomas E.C., McNeil, R.I. and Mullins, O: “Determination of Producible Hydrocarbon Type and Oil Quality in Wells Drilled with Synthetic Oil-based Muds,” SPE 39093, SPERE, no.2 (April 1999): 125-133. Hashem, M.N., Ugueto, G: “Wireline Formation Testers: Uses Beyond Pressures and Fluid Samples-A Viable Replacement of Production Tests,” Petrophysics, vol. 44, No.2 (April 2003): 108-115 Hashem, M.N., Elshahawi, H., Ugueto, G: “A Decade of formation testing – do’s and don’ts and tricks of the trade” presented at the SPWLA 45th Annual Logging Symposium held in Noordwijk, The Netherlands, June 6–9, 2004. Kuchuk, F.J.: “Interval Pressure Transient Testing With MDT Packer-Probe Module in Horizontal Wells,” SPEREE (December 1998) 509. Pop, J., Laastad, H., Eriksen, K. O., O’Keefe, M., Follini, J-M. and Dahle, T.: “Operational aspects of formation pressure measurements while drilling” paper SPE/IADC 92494 presented at the drilling conference held in Amsterdam, Netherlands, 23-25 February 2005. Shammai, M. and Hashem, M. “H2S Adsorption Study”, SPWLA Taos New Mexico 2004 Acknowledgements The authors would like to acknowledge the work of, Alistair Chandler, Rene Woertman, Kari Berge and Torgeir Stordal in the planning and execution of operations plus help with this article. About the authors Mohamed Hashem is a Senior Staff Petrophysical Engineer for Shell International E&P in Rijswijk, The Netherlands and is currently Shell’s group Principal Technical Expert for formation testing and sampling. Mohamed joined Shell in 1990 and has

worked on major deepwater and global projects in the GOM and around the world. He holds 8 patents on the wireline tester applications and techniques. Mohamed earned a BSC-ME from Ain-Shams University in Cairo, 1980; an MS-PE from USC, Los Angeles, 1987; and a D. Engineering in Petroleum Engineering from Stanford, California 1990. Alan McHardy is a Petrophysical Engineer in Norske Shell. He joined Shell in 2001. He has a Bsc in Geology and Physical Geography from the University of Edinburgh and an Msc in Petroleum Geoscience from The University of Aberdeen. Mike Wynne is a Senior Petroleum Engineer in Shell Technical Solutions in The Netherlands with 20 years of industry experience. He has a Bsc and PhD in Mathematics from the University of Bristol. Taco Viets is a Senior Reservoir Engineer in Norske Shell. He studied Mining engineering at Delft University. He has also worked in Holland, Oman, New Zealand and Scotland. Wilfred M.G. Pool is Lead Geoscientist in Norske Shell. He joined Shell in 1983 and worked in various countries both in Exploration and Production. He has a Bsc in Geology from Leiden University and an Msc in Geology from Utrecht University. Christof Keuser is a Petroleum Systems Analyst at Norske Shell. Prior to joining Shell in 2002, he worked for Integrated Exploration Systems GmbH, as a basin modeller. He graduated from the University of Cologne, Germany, with an M.Sc. degree in Geology

Kåre Otto Eriksen is a Well Data Acquisition Specialist in Statoil E&P. He joined Statoil in 1983 as a Petroleum Engineer and has mainly been involved in petrophysics, reservoir engineering, field development (sub surface activities) and well logging operation. The last 12 years as a Technical Advisor and Specialist in well data acquisition. He holds a Msc Degree in Petroleum Engineering from the University of Stavanger, Norway

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Table 1. Results of FPWD. Where available an estimate of supercharging is included, using the WFT derived gradient as formation pressure.

Wireline RCI (on-site) Well test

H2S H2Sconcentration concentration

Zone 1 1-2 ppm DST 2 14 - 18 ppm

Zone 2 6 ppm - -

Upper Zone 3 36 ppm - -

3 ppm4 ppm

H2S Concentration

Lower Zone 3 20 - 30 ppmDST 1

Table 2. Comparison of H2S levels from WFT and well test

Table 3. H2S study investigating the inhibitive properties of the RCI WFT (Shammai 2004).

Conclusions 1.H2S adsorption in the tool string and sampling tank is not dependent on pressure and temperature (up to 400°F) 2.Approximately 3 to 5ppm of H2S is adsorbed by the tool string regardless of the original concentration of the H2S in the sample 3.H2S adsorption is not time dependent (up to 7 days) 4.Pretreatment on MP35N does not effects the H2S adsorption 5.The H2S concentration in the stock solution remains constant during the experiment (control)

Test No. Zone Run Test Type Remarks Formation Pressure Drawdown Mobilitydegree of

Supercharging Pretest Volume Pretest Time Circ RateTime After

Drilling Depth inidicator

psia md/cp psi cc s lpm hr

1 1 1 B Not Stabilized 6975.80 0.8 na 0.18 0.94 1800 7.9 1


3 1 1 A Stabilized 11043.30 1.36 ? 2.13 1.25 1400 9.79 2

4 2 1 B Stabilized 11649.50 0.42 40.1 3.29 13.06 1785 5.03 3

5 2 1 A Stabilized 11682.90 0.21 73.5 0 1425 5.52 3



8 2 1 B Stabilized 11696.70 0.49 84.4 6.02 20.38 1800 6.41 6

9 2 1 A Stabilized 11677.50 0.44 65.2 0.52 3.69 1440 6.89 6

10 2 2 B Stabilized 11634.20 0.58 21.9 6.02 20.13 1785 32.33 6

11 2 2 A Stabilized 11623.90 0.52 11.6 0.52 3.63 1420 32.64 6

12 2 2 A Stabilized 11613.70 0.52 1.4 0.52 3.25 0 33.21 6

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FPWD vs. Annular pressure; Test 1

47000

47500

48000

48500

49000

49500

50000

100 150 200 250 300 350 400 450 500

T ime (secs )

Pre

ssur

e (K

PA

88000

88100

88200

88300

88400

88500

88600

88700

88800

88900

89000

Quartz guage P res sure

Annulus P ressure

Figure 1. An example of an unstabilised test from the FPWD tool. Both the initial and the main drawdown are clearly still building up. In addition, the sinusoidal oscillation of annular pressure due to mud circulation is reflected in the FPWD build up, indicating active pressure response from the borehole through the formation and into the tool probe.

FPWD vs. Annulus Pressure; Test 12

65000

67000

69000

71000

73000

75000

77000

79000

81000

83000

85000

87000

89000

0 200 400 600 800 1000 1200 1400

Time (Sec)

Pre

ssure

(KP

A

84500

84600

84700

84800

84900

85000

85100

85200

85300

85400

85500

Quartz guage pressure

Annulus pressure

Figure 2. An example of a stabilised test from the FPWD tool. The initial and the main drawdown are in close agreement. FPWD points 8 to 11 were also classified as good tests, with similar response to that illustrated here. This point was taken with no circulation.

Pressure vs Circulation rate

9

8

10

11

12

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11610

11620

11630

11640

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11660

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11690

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11710

0 200 400 600 800 1000 1200 1400 1600 1800 2000

Circulation rate (LPM)

Pres

sure

(psi

a)

Tests 8 - 9

Test 10 - 11

Test 12

Pumps off

9a

Pressure vs Circulation rate

9

8

10

11

12

11600

11610

11620

11630

11640

11650

11660

11670

11680

11690

11700

11710

0 200 400 600 800 1000 1200 1400 1600 1800 2000

Circulation rate (LPM)

Pres

sure

(psi

a)

Tests 8 - 9

Test 10 - 11

Test 12

Pumps off

9a

Figure 3. Stabilised pressure can be observed to decrease as circulation rate is dropped. The relative decrease is greatest between points 8 and 9, taken with shorter elapsed time after drilling

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Pressure vs Time after drilling

8

9

11

10

12

11600

11610

11620

11630

11640

11650

11660

11670

11680

11690

11700

11710

0 5 10 15 20 25 30 35

Time after drilling (HRS)

Pres

sure

(psi

a)

Tests 8-9

Tests 10 - 11

Test 12

Figure 4. Stabilised pressure can be observed to decrease as time after drilling increases.

FPWD vs. WFT key points

Tight abortTight abort


Tight abort

Tight abort


12 11 10 9 8

4500

4510

4520

4530

4540

4550

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4570

4580

4590

4600

4610

798.0 799.0 800.0 801.0 802.0 803.0 804.0 805.0 806.0

Reservoir Pressure (Bar)

TVD

SS (m

)

WFT pressures -Good points

WFT pressures -Other points

Gas gradient

Packer test builduppressure

Packer test builduppressure

FPWD data

Gradient calibrated from PVT sample

Figure 5. A drop of around 6 bars in stabilised pressure from one depth. The final point (pumps off) falls almost precisely upon the shallow extrapolation of subsequent wireline pressure gradient. The wireline pressure tester gave tight tests (tight / abort) over the region where FPWD data was successfully acquired.

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GR

0 150 GAPI

NEU

0.45 -0.15 FRAC

DEN

1.95 2.95 G/CM

NEU/DEN

RESISTIVITY

0.2 200 OHMM

Mini DST

0256 (RCI_PACK)

Core permeability insitu 0.01 1000 MD

Timor Coates

0.01 1000 MD

Mini DST Permeability

0.01 1000 MD

Mini DST test: K approx. 0.2 mD

Mini DST test: K - Too low to reliably interpret

GR

0 150 GAPI

NEU

0.45 -0.15 FRAC

DEN

1.95 2.95 G/CM

NEU/DEN

RESISTIVITY

0.2 200 OHMM

Mini DST

0256 (RCI_PACK)

Core permeability insitu 0.01 1000 MD

Timor Coates

0.01 1000 MD

Mini DST Permeability

0.01 1000 MD

Mini DST test: K approx. 0.2 mD

Mini DST test: K - Too low to reliably interpret

Figure 6. Log plot over cored interval where two dual packer tests were carried out. Uncertainties remain between core, packer and NMR derived permeability.

1

10

100

1000

0.001 0.01 0.1 1 10 100 1000

nm(p

) C

hang

e an

d D

eriv

ativ

e (p

si)

Elapsed time (mins)

Log-Log Match - Flow Period 21

Figure 7. The operational Log-Log diagnostic plot for zone 1 mini-DST. Permeability of around 0.2 mD could be interpreted

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Zone 1Comparison of Wellhead & Wireline Sample Compositions

0.00

0.01

0.02

0.03

0.04

0.05

0.06

0.07

0.08

0.09

0.10

C2/C1 C3/C1 C4/C1 C5/C1 C6+/C1

Ratios

Fra

ctio

nWell test Sample 1 Well test Sample 2Well test Sample 3Well test Sample 4Well test Sample 5 - cold trapWell test Sample 6RCI Lab Flash - Check Valve present - 10056875RCI Field Flash - Standard bottle - 369214RCI Lab Flash - Check Valve present - 10056448

Figure 8. Compositional comparison (Fractional weight %) between Well Test samples and RCI samples from Zone 1. Field flashed samples were non-nitrogen compensated bottles. The third sample is an outlier, the reasons for which at present are unexplained

Upper Zone 3 - No DST comparisonComparison of Wireline Sample Compositions

0.00

0.05

0.10

0.15

0.20

0.25

0.30

0.35

C2/C1 C3/C1 C4/C1 C5/C1 C6+/C1

Ratios

Fra

ctio

n

RCI Lab Flash - Check Valve present - 10056425

RCI Lab Flash - Check Valve present - 10056426

RCI Field Flash - Standard bottle - 10047689

Figure 9. Compositional analysis (Fractional weight %) for zone without a DST. This is a wetter gas than either of the DST zones.

Zone 3Comparison of Wellhead & Wireline Sample Compositions

0.00

0.01

0.02

0.03

0.04

0.05

0.06

0.07

0.08

C2/C1 C3/C1 C4/C1 C5/C1 C6+/C1

Ratios

Fra

ctio

n

Well test Sample 1Well test Sample 2Well test Sample 3

Well test Sample 4Well test Sample 5Well test Sample 6

RCI Lab Flash - Check Valve present - 10056373RCI Field Flash - Check Valve present - 10056392

Figure 10. Comparison of compositions (Fractional weight %) between RCI and DST samples for zone 2. RCI samples appear to contradict the DST samples.

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Figure 11. Carbon isotope data for DST, RCI samples and mudlogging. A good match is seen between the three datasets in the upper DST interval. In non-DST tested intervals the WFT samples match mudlogging data well. In the lower DST zone there is a clear change in the mudlogging carbon isotope values, correlating to a gamma ray peak. The WFT sample matches the mudlogging data at the point where the sample was acquired. The DST sample matches the mudlogging data from the upper portion of the tested interval. This is somewhat contradictory to expectation, because it is the lower part of the DST interval, which is thought to have highest reservoir quality, and thus could be expected to contribute the majority of the flow.

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HPHT LWD & EWL formation testing SPWLA 2006

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